Since the days of the Klondike Gold Rush, Yukon and mining have gone hand in hand. But these days there’s hope to develop another resource extraction industry in the territory – oil and gas. It’s not without its challenges though, as Northern Cross (Yukon) Ltd. is well aware. From the remoteness and the lack of infrastructure to a populace that’s unfamiliar with – and sometimes resistant to – oil and gas extraction, the company’s road to production is bound to be bumpy.

“Our preference would be to focus on something of a conventional nature.”

But Richard Wyman, the president of Northern Cross, isn’t backing away from the challenge. Despite calling the opportunities to develop conventional oil and gas resources in Yukon “modest” when compared to Alberta or B.C., he says, “The probabilities are that there’s both natural gas and crude oil to be found.” Plus, “The Yukon is an energy-intensive region, it’s got a cold climate, there’s a natural local appetite to consume either crude oil or upgraded product or natural gas.” But that market will need to grow and infrastructure to support energy firms working in the region will also need to be developed before companies like Northern Cross really strike gold.

Northern Cross’s interests are largely in the Eagle Plain region of northern Yukon. The company holds rights to about 5,000 square kilometers, but for the last three years it has focused most of its attention on a 400-square-kilometer area in the southern portion of its holdings. “We’re just scratching the surface,” Wyman says. The region Northern Cross has focused on initially is close to the Dempster Highway, which cuts across northern Yukon in a northeasterly direction and which provides year-round road access to the remote region.

Drilling decisions for the first four wells were made in part to satisfy commitments to the Yukon government to spend at least $20 million on the area in question. Wyman said the company has far exceeded those commitments, and has spent closer to $100 million, thanks in large part to investment from CNOOC International Inc. “This investment provides Northern Cross with the capital to honor its commitments in Yukon and provides longer term financial and technical support to advance Northern Cross’s business plan,” the company says on its website. With its obligations to the Yukon government now satisfied, decisions surrounding the next round of drilling will be based largely on geological information garnered from the first four wells and a seismic program completed last winter.

Unlike explorers tapping into prospective resource plays in Alberta, B.C. or Saskatchewan, Northern Cross is working with limited geological data. Some exploration did take place in the area prior to 1994, when the company was founded. In the 1950s, ’60s, and ’70s, about 30 vertical wells were drilled. The four wells Northern Cross has drilled in the region so far have all been vertical as well. “The unconventional resources, though, are going to be longer term,” Wyman says. “Our preference would be to focus on something of a conventional nature.”

That’s not true for other operators working in Yukon, particularly in the Liard Basin in the southeastern part of the territory. EFLO Energy Inc. is conducting natural gas exploration in the Liard, specifically in the Kotaneelee field. The area shares the same geological opportunities currently being exploited in northeast B.C. and the company currently has a 53.65 per cent general interest in a project in the field. It’s seeking to increase its share of the project to as much as 68 per cent, while Apache Corp. owns 32 per cent of the project.

Photograph courtesy of Northern Cross

During presentations before a Yukon government committee examining the potential risks and benefits of hydraulic fracturing in January 2014, H. Wayne Hamal, the chief operating officer of EFLO, noted that the Kotaneelee gas field produced more than 230 billion cubic feet of conventional gas before it was acquired by EFLO. “EFLO feels there remains significant volumes of both conventional and shale gas resources,” Hamal told the committee.

He went on to explain that “The existing infrastructure enables immediate delivery of produced gas through an existing dehydration gas plant and a Spectra Energy Corp. pipeline for delivery to Canadian and U.S. markets.” EFLO also believes that Kotaneelee gas could be chilled to form liquefied natural gas and “distributed throughout the Yukon to enable a less expensive, cleaner alternative fuel for power generation and vehicle consumption.”

“We’re living in a world of uncertain outcomes still, so we’re not quite at a point where we can declare we’re a sustainable business.”

The long-term success of EFLO in the Liard Basin may depend on the government’s pending decision to allow hydraulic fracturing to take place in the territory. During his presentation, Hamal said that the conventional resources in the Kotaneelee gas field might have five to 10 producing years remaining, while the shale potential has an estimated 50-year production life. In other potential oil and gas basins in the Yukon, activity is virtually nonexistent. While oil and gas exploration in the Beaufort-Mackenzie Basin in the Northwest Territories, for instance, is bustling there has been limited activity in the Yukon. According to the territorial government, “drilling on the Yukon portion of the basin to the west has been very limited. Three wells were completed showing no hydrocarbons and limited reservoir potential.”

Northern Cross is alone in its efforts to develop the Eagle Plain. One of the major challenges it faces, as did its predecessors in the ’70s, is the Eagle Plain’s distance from the oil field service and supply line industry. Yukon doesn’t have a developed service industry, so Northern Cross has to use what’s available out of B.C. and Alberta, a service line that’s some 2,000 to 3,000 kilometers long, according to Wyman. “If you were trying to conduct a similar operation to what we’re doing in Eagle Plain and did it in Alberta, you’d be no more than a few hours away from a supply center and you’re much closer to any kind of infrastructure related to emergency services in case you need it.”

The distance from emergency services means Northern Cross, which is still the only operator working to develop the Eagle Plain, must have appropriate emergency evacuation procedures and contingency plans in place, which layers on extra costs for the company. “You have to have redundancy and pieces of equipment so that if something has an unscheduled outage, you can seamlessly continue to operate with backup equipment,” Wyman says. “It’s not a forgiving place if you lose power and it’s January and it’s 45 degrees below outside.”

While Northern Cross is still firmly in the exploration phase, Wyman is hoping to bring some production online in the near future. “We’re in an area where there is no oil and gas infrastructure,” he says. “It’s going to be expensive to put all that stuff into place so we want to be pretty darn sure that we know what kind of resource mass we’re dealing with before we take the next steps.” Wyman’s crossing his fingers that the company discovers oil rather than natural gas. “As long as you can get a truck into a well that produces oil, you can start to move it. You can’t do the same thing with gas. It needs more infrastructure in place to get it into a shape so that you can transport it to market.”

Northern Cross has estimated the cost to transport oil to market from Eagle Plain will be in the range of $20 to $30 a barrel, depending on which markets it is delivered to. The company’s options range from trucking oil to existing terminals that can receive crude oil in northeastern B.C. or northwestern Alberta, or terminals that don’t exist yet in places like Skagway or Haines, Alaska.

Another uncertainty for the company is the price threshold at which production becomes cost effective. At this point, the current commodity prices for oil are high enough to allow for oil production, but the company would require a natural gas discovery of a certain mass to justify production given the infrastructure requirements – either a pipeline or a means of liquefying. “The main thing is that this is still an exploration project. We haven’t defined resources that can be earmarked as potential for commercial development yet, so I’m hoping that the interpretation of the seismic data will identify targets that will in turn become discoveries so we can take the next steps towards potential development,” Wyman says. “We’re living in a world of uncertain outcomes still, so we’re not quite at a point where we can declare we’re a sustainable business,” he added.

Despite the challenges, there are some things working in Northern Cross’s – and therefore the energy industry’s – favor in Yukon. A land use plan for northern Yukon accommodates oil and gas development in that region. No land use plan exists yet in the southeast, however, and a recent controversy over the government’s land use planning process in the Peel Watershed region has resulted in a legal challenge.

The Yukon government has included oil and gas development as part of its long-term energy and economic development agenda and the territory has a comprehensive policy and regulatory framework under which the oil and gas industry operates. What’s needed now, at least from Wyman’s perspective, is a discovery that’s big enough to be commercially developed.

Land Title Legalities

In July, Northern Cross wasn’t conducting any fieldwork on the Eagle Plain and only two or three caretakers were at the company’s camp, all of them Gwich’in. Northern Cross’s activities have been primarily conducted in the traditional territory of the Vuntut Gwitchin First Nation, although some of the seismic work was also conducted within the traditional territory of the First Nation of Na-Cho Nyäk Dun. Both First Nations are self-governing and have settled land claims.

Under the Yukon Oil and Gas Act, companies must reach a benefits agreement with any affected First Nations and the territorial government before carrying out any oil and gas-related activity. Wyman couldn’t provide the details of the benefits agreement between Northern Cross and the Vuntut Gwitchin, noting the agreements are only made public if all three parties agree.

He estimated that between 20 and 30 per cent of staff are hired from the territory, with a significant number of them hailing from Old Crow, the fly-in-fly-out Vuntut Gwitchin community in the northern part of the territory. He suggested that in the past around 20 per cent of the company’s spending has benefited Yukon businesses and people. Wyman said he hopes that percentage will increase over time, but again pointed to the underdeveloped oil and gas service sector.

]]>At long last, there’s again reason for optimism in Atlantic Canada’s offshore oil and gas industry. In late September 2013, Statoil ASA and its 35 per cent joint-venture partner, Husky Energy Inc., announced two back-to-back light crude discoveries in the deepwater Flemish Pass Basin, offshore Newfoundland. The larger of the two discoveries, the Bay du Nord exploration well, confirmed the existence of 300 to 600 million barrels of 34 degree API oil recoverable.

Located some 500 kilometers northeast of St. John’s, in 1,100 meters of water – and described as “high impact” by both companies – the Bay du Nord light oil discovery represents Statoil’s largest-ever operated discovery outside of Norway. Geir Richardsen, Statoil Canada’s vice-president of exploration, says followup plans include acquiring additional 3-D seismic surveys and drilling of exploration and appraisal wells in the largely unexplored Flemish Pass Basin. Depending on those results, the Bay du Nord discovery could be producing light crude sometime after 2020. “We rank the Grand Banks and the Flemish Pass Basin very highly,” Richardsen says. “Canada is a core area for us; it’s an environment where we hope to create good value.”

Hailed as the largest oil discovery off the coast of Newfoundland and Labrador in 30 years, the Bay du Nord well couldn’t have come at a more critical time. The discovery has opened up a new oil and gas frontier – from the continental slope to the deep water – that could reverse projected production declines and attract new players to several of its largely unexplored deepwater basins. The discovery has re-stoked another, somewhat presumptuous, ambition of the provincial government: to become an oil and gas producer in its own right.

According to the Canada-Newfoundland and Labrador Offshore Petroleum Board (the C-NLOBP), offshore production in the province is roughly 280,000 barrels of oil per day – or about 40 per cent of Canada’s light crude production. During the next decade, however, the maturing Hibernia, Terra Nova and White Rose fields will decline quickly. When Hebron, the fourth commercial energy project in the Jeanne d’Arc Basin, comes on stream in 2017, overall production will jump to approximately 320,000 bpd. After several years of peak oil production at Hebron, however, overall offshore production will resume on its projected decline curve.

Since the late 1990s, Statoil has been active in the area (through its predecessor Norsk Hydro ASA) and the company holds non-operated interests in the Hibernia and Terra Nova fields, the Hibernia tie-in and Hebron development fields, as well as non-operated interests in exploration licenses in the Jeanne d’Arc and East Orphan basins.

The Bay du Nord oil reservoir – a Jurassic-age sand with high porosity and permeability – lies two kilometers below the seabed. “It’s very much a standardized drilling process,” says Richardsen, partly because there are no overly high-pressured formations to contend with.

Map courtesy of Tgs

“Bay du Nord could become a giant field if the satellite blocks turn out to also contain light oil,” says Michael Enachescu, a professor of geophysics at Memorial University and chief geophysicist with Calgary-based MGM Energy Corp. “Bay du Nord could become the first deepwater development in offshore Canada.”

The three discoveries in the Flemish Pass Basin are located on separate geological structures, within 10 to 20 kilometers of each other. The Mizzen exploration well, drilled in 2009 by Statoil and its joint-venture partner, Husky, flowed 6,290 bpd of 22 degree API crude, and defined a resource of 100 to 200 million barrels of oil recoverable. The Statoil-operated light oil discovery at Harpoon, drilled in June 2013, will require additional appraisal wells to determine its magnitude.

Comparable in size to the Jeanne d’Arc Basin – which has been tested by 155 exploration and 55 development wells – the Flemish Pass Basin has been explored by just 10 wells to date. The Statoil-operated leases span 8,500 square kilometers, or roughly 75 per cent of the Flemish Pass Basin. The remainder of the basin is open Crown land, a portion of which will be publicly auctioned in 2014 by the C-NLOBP. In 2004, the C-NLOPB released a Flemish Pass Basin hydrocarbon resource assessment, calculating that it contained 1.7 billion barrels (at 50 per cent probability) with expected field sizes ranging from 44 million to 528 million barrels.

“The key to successful exploration is the presence of source rocks, and I believe that these basins are on the ‘Jurassic Superhighway’ that extends from Nova Scotia to the Grand Banks and the Flemish Pass, and across the Atlantic to the Irish Sea and the Porcupine Basin,” Enachescu says. The former Husky geophysicist, who has 30 years of experience in offshore Newfoundland exploration, adds that these discoveries “shine a new light on the potential of the Southeast Orphan and the Carson basins.”

The Statoil discoveries are fueling new optimism in the Atlantic province for oil and gas activity and, consequently, growing the ambitions of the provincial government. Derrick Dalley, the minister of natural resources for Newfoundland and Labrador, says the discovery “proves there is oil in our province’s deepwater basins, and it will encourage increased offshore exploration activity.”

In 2007, as part of a provincial energy strategy, the government of Newfoundland and Labrador created an arm’s-length Crown corporation called Nalcor Energy. Nalcor is involved in hydroelectricity, energy marketing and the construction of offshore energy infrastructure. The company also holds and manages the province’s equity “back-in” for offshore commercial energy projects.

In the mid-2000s, then-premier Danny Williams negotiated for a larger share of the offshore resource pie. He established the historic right, for the former “have not” province, to acquire up to a 10 per cent equity position in oil and gas projects requiring Development Plan Approvals by the federal and provincial governments. Under the terms of the equity ownership agreement, Nalcor pays a share of exploration and pre-development based on costs incurred by the joint-venture parties, then contributes its share of subsequent development and operational costs as needed.

Maps courtesy of Nalcor Energy

“We’re modeling ourselves after Statoil, says Jim Keating, vice-president of Nalcor’s oil and gas division. Statoil began in 1972 as Norway’s arm’s-length state oil company. Since then, it has evolved from exploring the Norwegian continental shelf (where it still produces two-thirds of its daily production) to a global exploration and production company that operates in more than 30 countries around the world. In 2001, Statoil was partially privatized and publicly listed, though the Norwegian state still owns a 67 per cent interest, which is managed by its Ministry of Petroleum and Energy.

Today, Nalcor produces between 3,000 to 4,000 bpd from its 10 per cent equity stake in the Hibernia South Extension and its five per cent equity stake in the White Rose Growth Project, which includes the North Amethyst Field, the West White Rose Field and the South White Rose Extension. Nalcor has also acquired a 4.9 per cent working interest in Hebron. Second in size to the giant Hibernia field, Hebron was discovered in 1980 and contains 400 million to 700 million barrels of 18 to 25 degree API oil recoverable.

When the Hibernia South Extension and Hebron fields both start producing, Keating estimates Nalcor’s production will increase to between 10,000 and 14,000 bpd. He claims Nalcor could be cash flow positive by 2016, enabling it to fund current and future oil and gas investments in onshore and offshore fields.

Independent of its equity purchases, Nalcor has undertaken an ambitious geological assessment of the province’s offshore hydrocarbon resources, including a regional rock physics study, a seabed core analysis study and the satellite imaging of hydrocarbon seeps emanating from the sea floor.

According to Keating, 85 per cent of Newfoundland and Labrador’s historical seismic data base is more than 15 years old; acquired with old technology, he said, this legacy 2-D seismic data would hardly attract new oil and gas investment to the province. During the past three years, Nalcor invested $15 million for a 20 per cent stake in 47,000 kilometers of new 2-D multi-client seismic data acquired by TGS-NOPEC Geophysical Company ASA,, a Norwegian seismic company that specializes in imaging frontier regions.

Working with TGS, Nalcor assisted in planning the 2-D seismic surveys, often locating them over active sea floor petroleum seeps. According to Keating, 75 per cent of the new 2-D multi-client seismic data is situated in the new oil and gas frontier: the continental slope and the deepwater. The multi-client seismic surveys are all available, for licensing, by industry. Nalcor’s investment is reaping some reward. The new 2-D seismic data revealed the existence of several new deepwater Tertiary-age geological basins offshore Labrador – Chidley, Henley and Holton – and extended the Hawke Basin. A small revelation in a region that has yet to be uncovered in full.

Young leaders in the energy industry are hard to come by. In a world run by old-timers, and swimming with sophomores fresh out of university, it’s just short of impossible for anyone in between to make real, concrete changes to the sector.

But there are a select few movers and shakers, young enough to understand modern forms of technologies and old enough to have a thorough understanding of the industry – the up-and-comers of generation X.

In terms of future leaders, there are many questions that need answering: What kind of leadership styles will they employ? Can the sector effectively attract new talent? Can it find the ideas people it needs? Here are four leaders with fresh ideas on the industry who are already bringing about change.

]]>Clay Riddell loves rocks. And therein lies the secret to his success with them, the reason this Manitoba-born geologist has become one of the most successful oilmen Alberta has ever seen.

When you love rocks as Clay Riddell loves them (he amassed his first collection at age four), you add to your scientific training and field experience an inimitable intuition for their potential. The kind of intuition that lets you take a modest investment in a pile of rocks in the 1970s, and parlay it into a family of companies the market cap of which exceeds $6 billion in 2013.

Left to right: Clay Riddell, Sue Riddell-Rose and Jim RiddellPhotograph Colin Way

But that’s not how Riddell will put it himself. As Paramount Resources Ltd. celebrates its 35th anniversary in 2013, the company’s 76-year-old founder, chairman and CEO is almost unbecomingly modest and reticent. He’s pleased at what he’s accomplished (how can he not be?), but reluctant to either extol his accomplishment or take credit for any particular vision, strategy or gift.

“There never was a grand plan,” Clay Riddell says. “When I started Paramount, I had only modest experience of running a couple of very tiny public companies prior to it, and our first issue was $5 million of stock. I had no visions of creating a company that grew to this.”

Nor, he says, had he a grand plan of building a family succession story, which is what Paramount has become. His son, Jim Riddell, now fills the roles of president and chief operating officer at Paramount and CEO and director at spinoff Trilogy Energy Corp. (Clay chairs its board) as well as executive chairman of the board of spin-off MGM Energy Corp. (Clay’s the official chairman) and executive chairman of the privately owned (and Riddell-controlled) Cavalier Energy Inc. (Clay’s a director). Meanwhile, Clay’s daughter, Sue Riddell-Rose, helms Perpetual Energy Inc., formerly Paramount Energy Trust, as president and CEO (Clay, of course, chairs its board).

“They share knowledge, both with each other, and with others. But they are different in terms of their management styles.”

Considering how tight this family of rock hounds is – Sue and Jim are both geologists – Clay’s claim that there never was a succession plan sounds almost disingenuous. But the 40-something kids seem to buy it. “I fully believe that if we weren’t capable of doing the job, he would have found somebody else to do it,” Jim says.

But we’re getting ahead of the story. Before he started handing the business off to his kids – who will hopefully build on his petroleum empire – the family patriarch had to build it up. It was not easy. “We had more setbacks than just the normal cycles of the business,” Clay says. “Our group of companies had more setbacks and interference than most others.” Never mind the economic and logistical challenges in the 1980s when the company was young. The 1990s weren’t easy either. That’s when the company built the last two National Energy Board-regulated gas pipelines into the Northwest Territories.

Its pipeline wrangles continue. The Mackenzie Gas Project, the pipeline that was critical to the long-term success of Paramount’s Northern-focused spin off, MGM Energy, isn’t within even a glimpse of the finish line. (“It will get built,” Riddell-Rose insists. “It’s just a matter of whether anyone sitting here at this table will still be alive.”)

The 2000s, when Paramount, and its new leaders, were hitting their stride, provided some hard times too. That’s when Paramount had to wrestle with Alberta’s Energy and Utilities Board for nearly a decade over its gas-over-bitumen extraction in the Surmont region of northern Alberta. And that’s when Riddell-Rose came into her own as a leader and spokesperson for the company and the industry, stepping into the spotlight her father actively eschewed to articulate the company’s position and agenda. It was good training for the role she would have to play in late 2006, when, with the ink barely dry on the creation of Paramount Energy Trust, she found herself fighting not just for the future of her company, but, in her role as co-chair of the Canadian Association of Energy Trusts, for the entire trust sector after the federal government suddenly decided to change the income tax rules so that income trusts holding Canadian assets would have to start paying corporate tax on pre-dividend earnings, just like a corporation.

It was a baptism by fire no one would claim to enjoy. But Riddell-Rose clearly owned and accepted being thrust into the spotlight much more than her father, arguably Calgary’s shyest billionaire, who keeps everything from his ownership in the Calgary Flames to his considerable philanthropic contributions as quiet as possible, ever did.

She is also more comfortable in the spotlight than her brother Jim, who would love to fly as below-the-radar of media and public scrutiny as his father has generally managed to. Be it from nature, nurture or a combination of the two, Jim shares an awful lot with his dad, including doing what needs to be done as unobtrusively as possible. He believes he’s learned “from the best oilman in Canada, the best explorer that I know of, who knows the geology and the oil business the best.” It’s hard to press him to identify how he plans to chart his own individual path – what it is that he might do with Paramount as he takes more and more of the leadership role. “I don’t know that I can pick things and say I do them differently,” he says. “Every day you come to work you try to make the best decisions for whatever problems you have in front of you. And whatever opportunities you have in front of you, if there isn’t a right answer, you either don’t make the decision or you guess. And that’s all I do, and I think that’s what he’s always done.”

Such talk from Paramount’s heir apparent might not sooth any worries shareholders have that Jim Riddell will be as successful steering the ship as his father has. But John Williams, president and CEO of Trilogy Energy, a company chasing tight gas and shale gas in Alberta’s red hot Duvernay play, thinks the family resemblance in leadership and vision is the real deal. “They are very similar,” Williams says. “They are both very smart, very knowledgeable and very intuitive. They share knowledge, both with each other, and with others. But they are different in terms of their management styles.”

Part of the difference has to do with age and experience. “Clay is this kind of wise old owl,” Williams says. “He just sits there and listens, and asks the questions. He wants to know if you understand what you’re doing. And he either trusts what you do or say or he doesn’t.”

Jim Riddell, Williams says, “is more engaged in the conversation with you.” Jim asks questions. The process of engaging with him is much more interactive. And there’s a touch of humility. He’s “still a kid,” Williams says. “He’s still learning.”

But then, Clay thinks he’s still learning too. If you read between the lines of what he says and what he thinks is the secret to the success of Paramount, and its eventual legacy to its non-related shareholders, it’s really that he rarely took anything for granted. And he still doesn’t.

“I think the way we grew Paramount, and with the succession, none of it was textbook,” Clay says. “I don’t think anybody would suggest you grow a company this way. I just didn’t know any better.” Some of what he did worked accordingly to plan (“I was worried it wouldn’t, so often I wouldn’t tell anyone what the plan was,” he confesses). Some of it failed.

The failures, suggests Riddell-Rose, gave the company and the family the opportunity to persevere, re-evaluate, learn and adapt. Through most of the 35 years of Paramount’s history, Clay steered the ship, and his children watched. “There never was any teaching,” Clay says. Riddell-Rose agrees. “It’s true. We were lucky we had good observation skills.”

And the biggest thing they learned is that it’s good to have options. “The one thing dad always did was build tons of optionality into our business,” Riddell-Rose says. When Paramount’s ventures have stumbled, it was when “we’ve structured ourselves in a way where we’ve eliminated some of that optionality,” she says.

“I don’t think anybody would suggest you grow a company this way. I just didn’t know any better.”

MGM Energy’s struggle to create value from its Northern oil and gas assets for shareholders, she suggests, is a case in point. It initially hitched its horse to natural gas and the Mackenzie Gas Project. Then the shale gale hit, North American prices sunk into a prolonged funk and the company suffered (MGM Energy has since shifted strategies and is chasing another Northern Star – the Canol shale oil play in the N.W.T’s central Mackenzie Valley.) When there have been options, flexibility and the ability to deploy capital and focus this way or that depending on the vagaries of the market, Paramount has prospered.

It’s a great strategy, right? Like Clay’s love of rocks and geology – the love that makes him make consistently smart bets on the next big thing – the love of optionality and its business consequences also stems from something more basic. As Riddell-Rose puts it to him: “You’re interested in a lot of different things.” The father nods. Eggs in different baskets. Or, more appropriately, rocks in different areas.

Companies in the oil patch often struggle with the decision of whether to stick to one thing they know well – oil sands, tight oil, liquids-rich natural gas – or diversify and give themselves options. Clay Riddell and his kin have chosen the latter path.

But is it the right one? Analysts like Adam Gill at CIBC World Markets Inc. dig the strategy. “The market is very positive over what Paramount has done over the last few years,” Gill says. It likes Paramount’s asset base, and its “potential in multiple horizons.” It’s excited over the company’s plans to build out infrastructure and ramp up production growth. Right now, Gill says the balance between its “diverse holding of assets” and its “focus,” particularly in its Kaybob business unit, pleases the market. The spin-out strategy, which created Trilogy, MGM, Perpetual and most recently Cavalier Energy Inc. – a subsidiary with in situ oil sands leases in Alberta’s Grand Rapids formation – is currently in favor, Gill says, “because the company has something material to work on to add volumes, but has not deprived itself of long-term opportunities, particularly in the oil sands.” Meanwhile, in the third quarter of 2012, Paramount was pumping out an average of 20,000 barrels of oil equivalent per day.

Left to right: Jim Riddell, Sue Riddell-Rose and Clay RiddellPhotograph Colin Way

His diverse interests notwithstanding, there is one thing that Clay Riddell is most emphatically not interested in. And that’s diluting the family interest in the Paramount companies. “We are very conscious about dilution of the holdings,” Clay says. “The biggest dilution is when we did the first issue, and I sold 40 per cent of the company for $5 million.”

Paramount and its public spin offs are, effectively, family-controlled public companies, a phenomenon of the Canadian capital markets with a lot of critics. But Clay is unapologetic. “Anybody that’s invested beside us has done incredibly well,” he says. Jim jumps in, “He’s never created any dual share structures or ever extended his influence beyond his ownership influence. I don’t think anybody can ever say he’s done more than just try and grow things for all of the shareholders and make the right decisions.”

The big question for Paramount’s other shareholders is will the “kids” make just as many right decisions and steer the company as competently as Clay has? The answer seems to be that they already are. On paper, Clay is still chairman and CEO of most of the sandbox, but he says Sue and Jim have been calling more and more of the shots. “Over time, Paramount is being run more and more by Jim and Sue,” he says. “It just happened gradually. Paramount was, compared to today, very small when they started making decisions and venturing opinions on how it should move forward.” What happens now at Paramount, he says, comes from Jim and Sue: “They come and tell me how it’s going to be, and they ask, ‘Do you think it’s OK?’”

But when will they stop asking Clay if it’s OK? And how might the course they chart for Paramount and its cadre of spinoffs be different from how their father operated? Jim thinks he can’t do better and can’t see how he’s different. But Riddell-Rose charts a more independent path. “Jim and Dad both have this incredible knack to see the full spectrum of our business and I think I have to rely a little bit more on my team for some things,” she says. There is another, potentially important divergence. Her dad has always had a penchant for leverage.

“I don’t wait until I have enough money to spend. I go to the bank and borrow and borrow lots. Debt is your friend as long as you’re right,” Clay says. Riddell-Rose shudders. “Having lived through a world of hurt the last few years with not enough optionality, I’m diminishing my debt right now, at Perpetual anyway,” she says.

Which is good news for Perpetual, and good news for Paramount. Learning from an oil patch legend is great training for the heirs and the shareholders they work for. But doing everything the way Clay Riddell did it just because that’s how he did it? That is the path to stagnation, not growth.

]]>Pipeline bottlenecks, price discounts and the uncertainty surrounding future projects like the Northern Gateway pipeline have oil producers in Western Canada searching for new outlets to reach new markets.

Photograph Churchill Gateway Development Corporation

One option is to send the crude by rail to ports that have traditionally shipped oil from other regions (like Alaska’s Port of Valdez) or handled other goods.

The Port of Churchill (pictured) in northern Manitoba falls into the latter category. The town, located on the west coast of Hudson Bay, has long been a key export point for western Canadian grain. Now it’s seeking to become an important export hub for the west’s oil – giving producers access to markets on the East Coast, Gulf Coast and Europe.

“We think we can provide them with a competitive cost advantage to position [oil] to multiple destinations,” Jeff McEachern, executive director of the Churchill Gateway Development Corp., told the Financial Post recently. The Winnipeg-based corporation was created in 2003 to market the port and diversify its traffic base.

Becoming an oil export hub would certainly do that. However, challenges must be overcome. The port is only ice-free from July to mid-October. The shipping season could be extended if shippers use icebreakers to accompany tankers, but that’s an expensive proposition. Shipping oil from Churchill could also face stiff opposition from aboriginal and environmental groups, who would fear oil spills in Hudson Bay’s pristine Arctic waters.

]]>http://www.albertaoilmagazine.com/2013/02/arctic-oil-churchill/feed/0Alberta’s Duvernay is a hot play once againhttp://www.albertaoilmagazine.com/2013/02/duvernay-hot-play/
http://www.albertaoilmagazine.com/2013/02/duvernay-hot-play/#commentsMon, 11 Feb 2013 14:30:23 +0000http://www.albertaoilmagazine.com/?p=19854Is the birthplace of the Leduc No. 1 oil discovery the province's next bonanza?

]]>The multibillion-barrel trove of energy that lies trapped in tombstone-dense rock across a vast tract of west-central Alberta is not all in the hands of the oil majors, says Brian McLachlan.

“Here, I’ll show you,” he says, jumping up from a boardroom chair and retrieving a map from the wall. “What I do believe we’re learning,” he says, spreading the oversized paper out on a table in the fashion of a 14th-century explorer, “is that certainly not all Duvernay is equal. You have to be in the sweet spots. And we are in a sweet spot – the thickest and the best part of the play.”

Yoho Resources CEO Brian McLachlan thinks his company is sitting in the sweet spot of the Duvernay playPhotograph Bryce Meyer

McLachlan, chief executive officer of Yoho Resources Inc., has quietly amassed 21 net sections in the Duvernay, in a window he believes is ideal for tapping a rich vein of rock soaked in petroleum liquids like propane and ethane.

By all appearances, McLachlan has positioned Yoho at ground zero of Alberta’s next petroleum bonanza. “So far we’ve had pretty good luck,” he says, noting that individual sections his company bought for $20,000 would now fetch $3 million. “Getting in early does help,” he adds, “especially when it starts working.”

“We’re delineating a mine. Maybe we cut a deal with the BHP [Billiton]s of the world to spend the big money.”

Crown land sales in Alberta have cooled dramatically since the buying frenzy of 2009, suggesting the play is indeed beginning to work. Sales of drilling rights totaled $579 million in the first six months of fiscal 2012, the province said in a second-quarter update. A recent land sale netted just $13 million, or $2 million shy of what Encana says it will cost to drill a single well on its Duvernay acreage.

The slowdown underlines the shift away from resource appraisal – the slow work of peering under rocks and gathering data – in a shale play said to rival the Eagle Ford in Texas in size and potential production.

“Everyone’s at varying stages [of development] depending on when they got in,” says McLachlan, whose outfit pumped an average of 2,200 barrels of oil equivalent in the year ended September 30, 2012. “But if you look at, for example, some of the Encana leases that they’ve licensed wells off of, the actual survey shows an eight-well pad. Shell’s drilling two wells off a pad already, so they’re actually ahead of us.”

Hydraulic fracturing crews and completions outfits are among those mobilizing in response to the activity. Trican Well Service Ltd., to take one example, recently moved into a renovated lumber mill on a 25-acre lot in Hinton to capitalize on new business in the region. It also owns operation bases in nearby Grande Prairie and Whitecourt.

Like others, Trican has been stung by tumbling natural gas prices and the resulting slowdown in field activity. It said third-quarter revenue fell 13 per cent last year, to $322 million, as the number of active drilling rigs in Western Canada fell by 28 per cent and completions declined 31 per cent compared to a year earlier. Canadian pricing declined six per cent over the same period, the company said.

A shift away from exploratory drilling toward “pad” production in the Duvernay might help reverse that trend, suggests Rob Cox, vice-president of Trican’s Canadian geographic unit. He says a “major” client is planning a four-well pad in the play, although he won’t say whom. “That tells us you’re getting past the exploratory phase and closer to the development phase,” he says in an interview.

The Duvernay is particularly attractive to pressure pumpers; it takes more energy to blast fissures in the formation that let trapped gas and oil flow. Horsepower requirements in the Duvernay, on wells with up to 15 stages per bore, are “on the high side, for sure,” Cox says, ranging from 17,000 to 30,000 hydraulic horsepower. “So you’re talking about needing anywhere from 15 to 20 or more horsepower pumpers just to do a frack.”

Only a fool would tail-gate the lumbering machinery that makes a shale gas well hum. Along a two-lane rural highway northwest of Edmonton during a late-November storm, convoys of half-tonne pickups, pressure pumpers and mobile rigs kick up their own weather systems of blowing snow and howling wind.

The trucks hauling gear into and out of hidden well sites belong to oilfield service giants Schlumberger, Halliburton and Baker Hughes, who have followed the explorers into the heart of the Duvernay. In the service hub of Whitecourt, Mayor Trevor Thain reports the telltale signs of an oncoming boom.

Hotel rooms are booked solid, he says. Workers are scarce and getting scarcer – the local paper, the Whitecourt Star, now boasts 10 pages of want ads, up from two previously, he says. Meanwhile, retail sales have been strong, Thain says. So have sales of industrial land. As of November, the town had made $400 million selling industrial-zoned lots in 2012, mostly to oilfield support businesses in welding, trucking and fluid hauling, the mayor says. “And we’re not done yet. There’s still lots in the fire,” he says.

The town’s proximity to the Kaybob liquids zone has been especially helpful. There are no hotel rooms in Fox Creek, the mayor says, where much of the activity is centered. “We’re seeing an influx of people that are moving into our community to service those areas,” Thain says, “even though they are upwards of 60 to 80 kilometers away from us.”

For drillers, the absence of amenities located in close proximity to the most promising acreage only serves to increase exploration costs. Last year, for instance, Yoho pumped $13.5 million into just one well – about 70 per cent more than what the company raised in a private placement of securities last fall. “But you’ve got to remember, this is one well,” McLachlan says. “You’ve got to move in all that water, all that equipment, for one well.”

He says costs will fall when multiple wells are drilled from a single pad. “You can imagine how much more efficient that is,” he says.

Convoys of half-tonne pickups, pressure pumpers and mobile rigs kick up their own weather systems of blowing snow and howling wind.

Another reason for optimism: monster yields of condensate and a ready-made market located next door in the oil sands. The ultra-light oil, which typically fetches a premium to the North American benchmark, West Texas Intermediate, is used by oil sands producers to make bitumen flow in pipelines. “The real key,” says Andrew Beaton, manager of the ERCB’s resource appraisal group, “is finding that right match where you have the right rock characteristics where you can actually get those liquids out.”

Producers that perfect the combination stand to make a lot of money. Energy consultancy Wood Mackenzie projects the Duvernay is so soaked in condensate that individual wells could generate revenue of between $4.6 million and $5.6 million each on a net present value basis.

Such windfalls only partially offset the capital required to commercially develop modern resource plays, however. McLachlan, who served as a director at Progress Energy Resources Corp., is not oblivious to the challenges faced by small companies with large holdings in promising resource plays. Yoho recorded an $8.8 million loss on falling gas prices in its last fiscal year. The company is carrying $18.5 million in debt and plans to spend between $35 million and $38 million this year, most of it in the Duvernay.

It takes a “small town” of equipment to bring a shale gas or oil well on stream, McLachlan says, turning philosophical. “Maybe the small company’s role has changed,” he muses, comparing Yoho to a junior mining outfit. “I don’t think this is a heck of a lot different,” he says. “We’re delineating the mine, and maybe we cut a deal with the BHP [Billiton]s of the world to spend the big money.”

Deals, Deals, Deals

Encana Corp. received an early Christmas gift in the form of $1.18 billion from PetroChina after the two companies agreed to work together to develop the Calgary natural gas producer’s Duvernay acreage.

Encana, Canada’s largest natural gas producer, agreed in December to sell a 49 per cent interest in more than 400,000 acres in the prospective shale field to Phoenix Duvernay Gas, a wholly owned subsidiary of PetroChina, for $2.2 billion.

Encana said $1.18 billion was paid on closing, with the remainder to come over a four-year development program that will see the companies spend a total of $4 billion on new drilling, completions and processing facilities, according to a statement. Encana estimates its Duvernay holdings contain nine billion barrels of oil equivalent.

The deal, announced less than a week after Ottawa approved the sale of Nexen Inc. to China’s CNOOC Ltd. and introduced new foreign investment rules for state-owned enterprises, “has big implications for Duvernay land valuations across the board which lends some credence to claims that the Duvernay could be the next Eagle Ford,” CIBC World Markets analyst Andrew Potter told clients in a note.

Among the smaller companies that stand to benefit the most is Trilogy Energy Corp. “They seem to be in the right postal code,” says Patrick Reddy, an equity analyst with Leith Wheeler Investment Counsel Ltd. in Vancouver. He owns shares in Encana and recently bought a “small position” in Trilogy. “They’re partnering on a handful of wells with Shell,” he says of Trilogy. “Their lands are adjacent to one another, so they’re well situated, but it’s still quite early.”

]]>Not every company sees the wisdom in chasing hydrocarbons in places like the Duvernay or the Cardium.

“I think building a road to known oil is much cheaper than paying $30,000-$40,000 per hectare buying a resource play in central Alberta,” says Gurpreet Sawhney, the president and CEO of Strategic Oil & Gas Ltd. – a Calgary-based junior focused on producing light conventional oil in northwestern Alberta.

Recognizing juniors can’t afford to acquire high-priced real estate if they don’t have enough cash left over to drill wells on it, Strategic has staked its claim in an area known as Steen River near the town of High Level in northern Alberta.

Drilling is costly in tight resource plays, requiring horizontal drilling and hydraulic fracturing to free hydrocarbons from the dense rock. But Strategic is drilling vertical wells on its Steen River assets. “It’s one area where vertical wells take eight days to drill and we can bring them into production at over 200 barrels per day,” Sawhney says.

With 5.2 million barrels of oil equivalent (boe) in proven and probable reserves booked, Strategic’s production has grown rapidly – from 303 boe per day (66 per cent of it oil) during the fourth quarter of 2010 to 2,047 boe per day (87 per cent oil) during the third quarter of 2012. Sawhney says Strategic exited the fourth quarter of 2012 producing 2,600 boe per day.

The company’s goal is to reach 5,000 boe per day during the next 14 to 16 months.

Drilling on its inventory of 350,000 net acres of land is where much of that production growth will come from. But the company, which currently has a market capitalization of $245 million, isn’t shy about growing by acquisition if a deal is the right fit.

In December, Strategic closed a $23.6 million deal with an unnamed private company and acquired 340 boe per day of production as well as 26 net sections of land at Steen River, pipelines and an off-loading station near the Mackenzie Highway, along with a 16-kilometer all-weather road. It’s the kind of deal Strategic looks for – one where it not only acquires land, but also production and the infrastructure to get it to market.

While Strategic sets its sights on hitting the 5,000 boe per day production target over the next year, Sawhney and his team have bigger goals for the company – to reach the 10,000 boe per day level over the next three years. They will do that by working on their Steen River assets. But the company also has unconventional oil it is going after in the Keg River and Sulphur Point areas located on the Steen River acreage, as well as in the Liard Basin in northern British Columbia. Sawhney adds that Strategic’s shareholders are not in this to grow the company and then sell it to the highest bidder. “Why stop a good thing that is going on? If you look at our asset base and the wells we’ve drilled, we’re just getting started.”

]]>The Challenge
Quinn Holtby, president and chief executive of Katch Kan Ltd., realized early on that a standardized training program would be necessary to make sure the company’s systems were installed correctly, no matter where in the world they were being used.

“We’ve always done our training this way because we needed a level of consistency,” he says. “Right from Day 1 in Canada, our first priority was to make sure everyone was certified.”

The private company’s first patented system was installed in 1994. The services company manufactures and sells safety equipment for onshore, offshore and well-servicing rigs. Holtby originally created a cylinder that would clasp around the drill and prevent fluid from spilling onto the rig floor whenever the drill was pulled out.

The company has developed several other products that improve safety on a rig. Katch Kan also developed a system that combines several of its products and not only prevents fluid from covering surfaces of a rig, but collects fluid so it can be reused in operations.

The Edmonton-based company now has more than 100 employees spread across 61 countries.

The StrategyEvery employee of Katch Kan is brought to the company’s head office in south Edmonton for training. “It’s mandatory because they need to know what the equipment does,” Holtby says.

Language is Katch Kan’s biggest barrier in delivering a consistent training program, so Holtby brought people in to develop training programs for people who did not speak English. Visual exercises also play a key role in breaking down language barriers. Katch Kan invested in a simulator five years ago to help solve that challenge. The company also moved into a 50,000-square-foot facility to accommodate the new equipment and provide a better environment for training.

“It is equipped with a service rig simulator, a drilling rig simulator and a wellhead simulator,” Holtby says. “We’ve built it so it can be modified. You can set it to different configurations and rig stacks. You can train someone on single, double, triple, jackup and offshore rigs.”

Katch Kan’s training program was developed in-house and includes five levels of certification. Every employee goes through the first level of training, which details the installation and removal of the company’s different products and systems. The level one training course takes one week and includes five installations in Canada.

The level two and three courses provide more extensive training on safety to allow employees who complete those levels to become subject matter experts. Both levels also include communication components, which provide training on how to properly interact with workers on a rig or office supervisors, depending on the level of certification. The level five training course, meanwhile, takes one month to complete.

Katch Kan also gathers its country managers from around the world in Edmonton for one month every year for course updates and certificate of recognition training. “The training also gives us an opportunity to measure how effective our employees are,” Holtby says. “We can measure the installation and measure safety on the rig.”

The Payoff
Holtby estimates Katch Kan spends about 300 per cent more on training by bringing its employees to Edmonton rather than having a trainer travel to a foreign country. The extra costs are not just for training, however.

Holtby says that during the annual country manager meeting in 2011, the company included a five-day travel plan that allowed international employees to visit the Rocky Mountains. “I firmly believe synergy is built on having people come here to see our operations and live our values,” he says.

But, he says, the additional cost has been worth it. Ensuring systems are properly installed and improving rig safety is the main reason the company has been able to expand its operations to more than 60 countries.

“Most oil companies are attuned to the fact that things can be done better,” Holtby says. “Our goal isn’t just to deliver our systems. Our country managers are always looking at other technologies from Canada that can be passed on to operations in other countries.”

Joe Dion and Dong Wang struck a $30-million deal without ever speaking a word to each other.

The chairman and chief executive of Frog Lake Energy Resources Corp. (FLERC) and the president of Sichuan Ruifeng Investment Management Co. Ltd., respectively, used an interpreter to negotiate the creation of Windtalker Energy Corp. in November 2010.

The $30 million gave Dong’s private investment firm a 90 per cent stake in the new oil production company and its first subsidiary outside of China. FLERC retained a 10 per cent stake in the new company and got the capital necessary to try and turn about three million barrels of proved plus probable oil reserves into a 100,000 barrel per day (bpd) operation.

“There was doubt about our ability to get capital in China.”

“Capital is moving around the world and becoming scarce in North America,” Dion says. “There was doubt about our ability to get capital in China. We did not go for the big guys like other companies in Calgary are doing. We went with the smaller businessman. We think we can develop this business and this relationship so we can attract bigger guys.”

Dion has never been shy about his ambitions for developing Frog Lake First Nation reserve land in the heavy oil belt northwest of Lloydminster. The Kehewin Cree Nation hereditary chief founded the Indian Resource Council of Canada in 1984, which represents 130 First Nations with oil and natural gas resources on their land. He also established Indian Oil and Gas Canada in 1987, which is a federal government agency designed to help manage oil and natural gas development on reserve lands.

FLERC, meanwhile, was launched in 2000 and became the first wholly First Nation-owned oil producer. With about 2,500 members, Frog Lake First Nation lacked the capital to operate a drilling program on its lands. FLERC established partnerships with two companies that were later acquired by Canadian Natural Resources Ltd. and Twin Butte Energy Ltd. The company’s production grew to 1,300 bpd by 2010. Dion wanted FLERC to double that production the next year. The company ended its fiscal year with production averaging 2,680 bpd during March 2011.

FLERC drilled 87 wells during that fiscal year, but Dion says the company is only tapping five or six per cent of its reserves. Directional drilling and new technology will help the company produce more of the heavy oil under its lands, so Dion needed to raise money to fund a more expensive operational program. From FLERC’s corporate office downtown in Calgary, Dion went looking for capital and met Dong Wang. “We did talk to our existing partners and there were companies in Calgary that made us offers,” Dion says. “But the terms were not as good as the ones offered by Dong Wang’s group.”

Dong’s company holds an estimated $100 million in assets. The company has 20 subsidiaries in China. Sichuan Ruifeng Investment Management dabbles in hydro power, agriculture, mortgage financing and coal. Dong owns at least 80 per cent of each subsidiary. He serves as the chief executive of most of them, which is his official role with Windtalker.

During a visit this summer to Calgary, Dong said through an interpreter that the Chinese government and banks are supporting companies to make investments around the world. “Right now in China the demand for oil is higher,” says Jan Lin, investment director with the Chinese firm. “They have invested a lot of money in Canada and Canada has a lot of resources.”

The investment in Windtalker will help produce resources from the heavy oil formation under Frog Lake First Nation land. The company is also exploring growth options by acquiring land or production in Alberta, other parts of Canada and the United States. “Then, if the market is good we’ll go public,” Lin says.
Dion says part of Windtalker’s success will depend on being able to get its oil production to market. And that means having projects like Enbridge Inc.’s Northern Gateway pipeline built to Canada’s West Coast.

“We’re in the business of making oil and we’re in the business of shipping this oil to where we’ll get the best price. As a First Nation, we support these kinds of projects that will create employment for our people and bring bigger profits,” Dion says.

]]>Like many people, Peter Stalenhoef downplays his role in his workplace. Unlike most people, however, Stalenhoef oversees industrial construction projects that gross almost double the GDP of Liberia every year. “You’re always running a volume, hopefully, of around $2.5 billion annually,” says the chief operating officer of the heavy industrial arm of PCL Construction. “That’s where we’re currently at.”

The largest construction firm in the country, Edmonton-based PCL’s big money-maker is its buildings division, which builds everything from sports arenas to federal courthouses to airports, including portions of terminals in Edmonton and Vancouver. But Stalenhoef’s division follows close behind, hauling in a third of PCL’s total revenues despite restricting its operations to North America, unlike the other two arms of the firm.

PCL’s modular construction facilities around Edmonton, where thousands of tradespeople assemble pipe rack add-ons to oil sands plants, are fully booked into 2014. One of the biggest challenges Stalenhoef faces these days is deciding which work he must turn down and how fast he can expand facilities. “It’s all a function of capacity,” he says. “We can’t do everything.”

But they aim to come as close as they can. PCL already commands more modular construction capability than any other firm in Alberta, and it recently opened another 40-acre plant in east Edmonton. Unlike its 110- and 70-acre plants in nearby Nisku, PCL is leasing this latest one – understandable, since the facilities cost around $1 million an acre to construct. PCL makes a lot of money, but it still watches capital expenditures closely, especially in the energy sector, where volatility is the norm. “We try not to be pregnant with a bunch of buildings that we might not require,” Stalenhoef says.

Such disciplined thinking informed the firm’s move into modular construction in the late ’90s. Fed up with persuading tradespeople to spend extended periods of time in the bush,

PCL’s leadership decided to invest in controlled construction environments that would allow more efficient, higher-quality work and let employees spend their nights in the beds of their own choosing. The choice of location, according to Stalenhoef, was a natural one.

“We try not to be pregnant with a bunch of buildings that we might not require.”

“Alberta’s set up with specialized shipping corridors that accommodate heavy, wide loads,” he says. “That’s helped fast-track a lot of projects and kept a lot of man-hours off the sites.” The plants load their output onto semis, which then haul them to oil sands projects.

But the most assiduously placed and immaculately built construction plant means nothing if there are no workers available, and lately PCL has struggled to find appropriate staff. “There’s more opportunity in Alberta than there are people to serve it, so that’s a challenging perspective when it comes to recruiting,” says Stalenhoef. At PCL’s headquarters in south-central Edmonton, hiring signs festoon 99th Street like parched cacti in a desert.

If misery really does love company, Stalenhoef can at least take solace in the thought that PCL is not alone. Unemployment is under 4.4 per cent in the province. And Edmonton employers are the most bullish in the country, according to a September survey conducted by employment services firm Manpower. The race to find quality employees is as hotly run as ever in Alberta.

This is why Stalenhoef reacts tepidly to the idea of bidding for work on any of the contentious proposed pipeline projects that periodically convulse the news cycle: Enbridge Inc.’s Northern Gateway, Kinder Morgan Canada’s Trans Mountain, or TransCanada Corp.’s Keystone XL expansion. Stalenhoef sees Northern Gateway, for instance, as a necessary boost to the price of Alberta crude on world markets, and PCL has serious pipeline experience – it built the Alberta Group 1 pump stations for the original Keystone, finishing construction in 2009 after sinking 600,000 hours of labor into a work site 300 kilometers long. But with the difficulty of finding the right people and a full slate of work already booked for 2013, getting contracts on any of these pipelines is hardly a make-or-break proposition for PCL’s heavy industrial division.

In fact, the difficulty of finding space on any contractor’s schedule can drive the companies that commission major energy infrastructure projects to distraction. Most majors contract out their infrastructure development, so a bottleneck there can act as a limiter on the growth of the entire energy sector in the province. This happened during the last boom, and given PCL’s construction schedule, history may be repeating itself.

One solution is to develop infrastructure solutions in-house. Cenovus Energy Inc. grew so annoyed with contractor timing, expense and quality issues during the boom of the mid-2000s that it built its own 45-acre modular construction factory in Nisku. The yard can build 65 pipe rack modules at once, and churns out 15 a month for the company’s Foster Creek and Christina Lake oil sands projects.

While the firm still needs to contract out a substantial portion of its construction, the ability to make even half of what it needs to its own satisfaction counts for a lot, according to the company’s mobile construction head Dave Zebak.

And it lets Cenovus build at whatever pace it wants, enabling something Zebak calls a “bite-sized” approach to projects, breaking them up into many smaller ones. “It gives us a greater level of control and input in the entire process,” Zebak says. It also increases accountability: “Ultimately, it’s our funds that are being spent.”

For the construction that Cenovus’s yard can’t handle, which ranges from two-thirds to a half of what it needs done, according to Zebak, the company looks for contractors it knows and trusts. Stalenhoef says PCL does likewise when deciding where to bid for work. Of course, the fluctuations in the global economy have brought more foreign competition to Alberta recently. “If you’re in Europe right now and searching for projects to build, you’re probably looking at a very short list,” Stalenhoef says. “We’re seeing more European contractors coming here and looking for work.”

Even this can work out in PCL’s favor, though, since a European firm awarded a contract likely still needs to get it built in Alberta – there’s very little profit in shipping pipe rack modules over the Atlantic and then across the continent to northern Alberta. In early September, Stalenhoef indicated that PCL was in negotiations for just such work, though he declined to name the specific firm.

Nor does he have to. Employee-owned since 1977, PCL ranks as the second-biggest company in Edmonton, with annual revenue approaching $6 billion. But despite working in the capital-intensive construction business, it sees little upside in going public. “We’ve shied away from being a publicly traded company for lots of reasons,” Stalenhoef says. “There’s an enormous cost to it. We’ve just chosen to stay private as long as we can, and we don’t see any reason we can’t sustain that for many years to come.”

Given that he’s been with the company through booms and busts for 25 years, he should know. “You’ve got so much to do that you don’t have to worry about looking for another job,” he says with a laugh. “It’s a great place to work.”

The Stikine River cuts through 500 kilometers of glacier and rock in northwest British Columbia and Alaska. Before it empties into the Pacific near Wrangell, the river hurtles down a roiling stretch of hell called the Grand Canyon of the Stikine. Though the provincial government classifies the canyon as totally impassable by anything or anyone, crazed kayakers successfully ran it 15 times between 1989 and 2006.

As chief executive officer of a mining company that bears the name of the same river, Scott Broughton needs similarly steely nerves these days. In 2009, his Vancouver-based company ditched the gold business to bet on an explosion in shale gas drilling.

Since then, gold prices continued to climb, rising 40 per cent, while the price of natural gas plunged, dragging the TSX Venture-listed company’s stock down with it. “I’m not sure it’s all going successfully at the moment,” says the CEO and president of Stikine Energy Corp. “It’s been a pretty difficult story to tell with not a very broad audience, with gas prices where they’re at.”

But that audience is poised to grow if the next three years pan out the way Broughton hopes. Stikine has proposed developing two open-pit mines – dubbed Angus and Nonda – that abut B.C.’s big shale gas plays. Both projects will produce silica sand used in hydraulic fracturing operations as a proppant to hold fissures blasted into dense rock open. These fissures are what allow oil, liquids and solids to flow to the wellhead.

Like its namesake river, Stikine is cutting through virgin territory. Perhaps more striking, however, is the company’s ambition. It believes its mines are rich enough to supply so-called frack sand for nothing less than the entire life cycle of every shale gas basin in B.C.

The projection is no doubt brash, not least because Stikine’s entire business plan is inextricably bound to the western province’s budding boom in liquefied natural gas (LNG). Three planned coastal projects that would ship supercooled B.C. gas to Pacific markets are scheduled to begin operation by 2020.

The proposed export volumes are staggering. Shell alone plans to ship 24 million tonnes of LNG, or 3.4 billion cubic feet of gas per day, to overseas markets. The total, equivalent to a quarter of Canada’s total output in 2011, will require a tremendous amount of drilling.

Broughton knows this. In a way, Stikine is setting itself up in the fashion of a proprietor of a hardware store in a gold mining town. Broughton is banking on LNG developments to kick-start drilling and demand for frack sand.

What’s more, he says Stikine’s proposed mines, because of their close proximity, could supply sand to well sites in the nearby Montney and Horn River gas plays at a fraction of the cost Encana Corp., Shell, Talisman Energy Inc. and others currently pay for the stuff.

His bid to undercut current suppliers like Sil Industrial Minerals and Radnor, Pennsylvania-based Preferred Sands LLC is supported by the oldest rule in real estate: location, location, location. “This is specific to the northeast of B.C., but around 70 per cent of the cost of frack sand is just shipping and handling of the material,” he says.

A Stikine investor presentation in early 2012 puts the figure higher still, pegging the proportion of transport costs at 80 per cent per tonne of sand bound for B.C.’s Horn River play. To get one tonne of sand to a well in B.C., operators like Apache, Encana and Nexen pay anywhere from $250 to $500 – this for a product that costs around $60 a tonne to produce.

Broughton traces the markup back to the cost of hauling the material thousands of kilometers from mines in Saskatchewan and as far afield as Wisconsin and Texas.

Those costs generated enough cash to earn lavish praise from Canadian National Railway executive vice-president Jean-Jacques Ruest on the company’s second-quarter earnings call. He described the sudden interest in moving sand as “a phenomenal progression,” according to a transcript of the call, and noted that CN is in the process of investing $35 million in Wisconsin to access a new mine opening this year.

Stikine, by comparison, can eschew the middleman. The junior miner believes it can make a healthy profit charging drillers in the province a price close to Stikine’s nearest competitors delivered prices.

One thing is clear: demand for the proppant appears poised to skyrocket. In September 2011, the Canadian Association of Petroleum Producers estimated the Horn River and Montney plays near Fort St. John and Fort Nelson are big enough to provide 100 years of natural gas supply.

In June, Apache announced a find big enough to pop the eyes of energy analysts everywhere: the company estimates its Liard Basin holdings could yield 48 trillion cubic feet of marketable gas. The estimate is based on test results from a single well described by Apache Corp. chairman and chief executive officer Steven Farris as “one of the best shale wells we’ve seen in any play.”

Well completions in the Laird formation, together with the Montney and Horn River, could amount to demand for upwards of six million of tonnes of sand per year by 2015, Stikine projects. That could translate into a brisk trade, provided the company can secure financing. Pre-development costs for the two mines are pegged at roughly $970 million.

“There’s no equity financing to do; that’s just absent completely,” Broughton says. “Same across the sector – it’s impossible for most junior mining companies to raise anything right now.”

Stikine Energy Corp. CEO Scott BroughtonPhotograph Phillip Chin

It also seems impossible for Stikine to raise its stock price above the cost of a cup of coffee. Since peaking at $0.72 in 2004, the company’s price on the Venture exchange looks like the outline of a mountain range slowly succumbing to the power of erosion; it hasn’t traded above $0.15 since March.

If Stikine can hang on until drills in B.C. start to spin en masse, it could mean a remarkable turnaround for a company that debuted on the TSX in 2003. Broughton, along with fellow Stikine executives David Skerlec and Robert Chambers, had just gone public with another venture, Roca Mines Inc., where he is also chief executive officer, when Stikine Gold Corporation made its public debut.

The trio of executives seemed poised to collect a packet thanks to promising gold mineralization tests at Stikine’s Williams Lake project near Toodoggone Lake in B.C. But additional research revealed the deposits were uneconomic to operate, and the company’s other forays into copper, gold and uranium also failed to pan out.

In June of 2010 the company changed its name to Stikine Energy Corporation to reflect its retooling toward frack sand. (Roca Mines likewise dabbled in base and precious metals before eventually settling into mining molybdenum, which is used in stainless and structural steel as an alloying agent. The company’s stock also mimics Stikine’s, trading below $0.06 since March).

Broughton spent the first half of his career as a consulting cog in much larger mining companies. The experience informs his current outlook. He reports no regrets about starting either Stikine or Roca, which is considering an exit from the molybdenum business as part of a strategic review.

“It’s difficult, but there’s the old adage – you have to give the market what it wants. Right now, the market doesn’t want this,” he says of Stikine. “Yet there was a moment in time when the market was there and had an appetite for it and we raised a fair amount of cash. In the long term, we’ll show that the story was good.”

Athabasca Oil Corp. CEO Sveinung Svarte got a taste of profit as a kid selling berries in Norway. Today, he’s harvesting a much more lucrative patchPhotograph Colin Way

Every Norwegian kid knows that of all the berries, cloudberries are the best. They are small and delicate, like diminutive orange raspberries whose taste, which some compare to sweet wine, is coveted. They are rare, growing wild on mountain meadows and marshes, and they are beautiful, facing the heavens like a flower. Unsurprisingly, that has made them valuable. To some, they are “highland gold.”

To Sveinung Svarte, they were an early taste of what could happen when he applied a little smarts to a precious commodity. His parents picked them for their own use. He hired a couple of local kids to do the picking, and pocketed the proceeds. “They’re really expensive, and as a kid you make a fortune out of that,” says Svarte, who has long since been transplanted from Norway’s slopes to Calgary’s downtown towers. But distance and time haven’t changed that one trait: he is still looking for ways to mine profit from something everyone wants.

Svarte is the CEO of Athabasca Oil Corp., a company that, in its opening days in 2006, convinced investors to put down $100 million for assets the company would not then reveal. All they could say was that they were chasing the closest thing Alberta has to the cloudberry: the oil sands.

Athabasca was one of the biggest energy IPOs in Canada. It’s also been one of the biggest disappointments.

Those who took that initial bet were rewarded. Since its formation, Athabasca has been among the most aggressive companies in Alberta.

It has found oil by the billions of barrels, and then pulled in $1.35 billion from an IPO that landed at a market peak. It sold 60 per cent of two projects to PetroChina for $1.9 billion, then the remainder of one of those projects for another $680 million. What’s left of the second project, which it’s broadly expected to sell, could yield another $1.3 billion, plus the company has not been shy about saying it’s working up another big deal that could land any day.

All the while, it has scoured the province for land it could snap up before anyone else saw its value, amassing a huge position– some 3.5 million net acres – after a buying binge that made it, chairman Bill Gallacher believes, the most active land buyer at public auctions “in Alberta for four or five years.”

Oh, and along the way it did an about-face. In May, Athabasca Oil Sands Corp., as it was initially called, became Athabasca Oil Corp., after the company that built a quick fortune around Fort McMurray completed a transition into a company whose ambitions now span Alberta. The Fort McMurray berry patch, it turned out, wasn’t big enough for Svarte. Nearly 60 per cent of Athabasca’s land now sits outside the oil sands, on the other side of the province in the so-called “deep basin” where instead of heavy bitumen, extra-light oil surges to the surface with natural gas. The company has boasted that in the span of just eight years, it will be pumping somewhere between 200,000 and 260,000 barrels per day.

Today, it pumps 7,000 (although that amount is still waiting to be tied into a pipeline). It recently signed a lease for several floors in a not-yet-built tower, where it will have space for some 650 employees. Its current roster stands just over 300. It talks about a huge trove of oil, some 10.4 billion potentially recoverable barrels. But its proven reserves stand at 8.4 million barrels.

There is, in other words, a lot of work for Athabasca to do to prove to antsy investors, who have seen their shares slump dramatically since the IPO, that it can actually produce the bumper crop it keeps promising. “The onus is on us to show it,” says Bryan Gould, Athabasca’s vice-president of corporate development.

To understand Athabasca, a company that has embraced foreign partners, made no apologies about dramatic changes to its business strategy and leavened it all with a healthy dose of big ambition, it doesn’t hurt to understand Svarte. He grew up in a small town in Norway in a family of teachers and engineers and opted for a career in oil and gas. But the most natural employer, what is now Statoil, the Norwegian national oil company, was never high on his list. He wasn’t up for a stodgy career. “I was never really drawn to those state type enterprises,” he says. “And I wanted to see the world.”

So after studying engineering, he left for the United Kingdom to work in the North Sea for Conoco. He moved to Paris and eventually took up with Total, a company that once again dispatched him far and wide. His work took him to South America, Kazakhstan, Russia, Azerbaijan, Asia and Africa. He came to Canada in 2005 and found himself working for a company that had, at the time, barely a dozen employees, but big dreams for Alberta, where it would pledge $20 billion in investments around Fort McMurray.

As vice-president of oil sands, it was Svarte’s job to grow those dreams. He was there when Total bought out Deer Creek Energy for $1.67 billion. He discovered that he liked working in the oil sands, whose scale resonated with things he had done before.

“I worked in Kazakhstan before I came here. And typically in the Caspian Sea, you’re talking about 12 billion barrels recoverable,” he says. “So I think if I had gotten to work on small things here, I would have had a hard time to find motivation for it.”

Plus, he liked the idea of transforming the boreal forest into something else. “To me, it’s a challenge of building things,” he says.

That perspective came in handy when Bill Gallacher came calling. Gallacher had, together with Ian Atkinson, a Calgary-based engineer who is now Athabasca Oil Corp.’s vice-president of geoscience and development, found what they believed was a huge overlooked asset. Reviewing microfiche and core samples a half-century old, some of which had not been opened in many years, they found promise in areas west of the traditional oil sands development zone. “We found pure bitumen,” Gallacher says. “So we started a bidding process to acquire the land.”

But they needed someone to run the company. Gallacher and Svarte started talking. In one conversation, Gallacher asked Svarte to note the things he wanted in a company. The resulting wishes – a big company with big money and a big, contiguous land position – almost perfectly matched a list Gallacher had scrawled on a paper and brought to the meeting. Svarte was hired in 2006.

It didn’t take much thinking to conclude, though, that developing a prize the size of the oil sands was not something a couple of guys with a dream, or even $100 million, could do. But Svarte had a different perspective from many others in Calgary. He had no philosophical problem with grabbing outside dollars through joint venture partners.

“All the way from day one we thought that was the model,” he says. “To me it was natural, because every international oil and gas development consists of normally two to four partners.” Plus, when he went to drum up interest, he had a Rolodex that came in handy. While still with Total, he had worked in both Kazakhstan and eastern Siberia alongside PetroChina, the company engaged in their initial deal, a joint venture that could ultimately be worth $3.9 billion.

It was the first. It will not be the last. A second joint venture – also for oil sands assets, though not as big as the first – is on its way. Another will probably be needed to tap the firm’s carbonate rocks, which require technological ingenuity to access and which could one day produce 400,000 barrels a day. Yet another will likely be called upon to finance the remaking of Athabasca and its foray into the deep basin.

That move has dramatically changed the complexion of a company that had put down roots in the Fort McMurray area and looked like an oil sands company. The way Svarte tells it, it came down, in part at least, to corporate boredom. Athabasca’s exploration team had done its work in the oil sands. It was looking for something else to do, and saw the early days of the Bakken boom in the United States, where underground fracking was bringing huge new volumes of oil to surface. They figured the same must be true in Canada, and started looking around.

“We saw all this land available after we did the studies and figured, ‘We really like this,’ “ Svarte says. It was an about-face for a company built on the oil sands, and Athabasca acknowledges a good half of its investor base was initially unhappy. But Svarte had grown up in big diverse companies, so “I was probably more open to seeing a bit of a bigger picture and trying to grow a bit more.”

Plus, fracked oil promised a major bonus: cash flow. Deep basin crude is costly to develop – at $10 million a well, it adds up quick. But the oil comes on fast, paying back costs in a hurry, and at a higher profit, with an expected 30-plus per cent return. That makes it a cash generator for the oil sands, where an expected return in the teens is lower but can be sustained for much longer.

“You always worry about being pure play or not,” Svarte says. “But I’ve seen so many times through history that companies who were not pure play have split up to become that and regret it afterwards.”

Athabasca Oil Corp. CEO Sveinung SvartePhotograph Colin Way

The deal is coming. It’s just around the corner. It’s almost here. Executive vacation plans are being cancelled to make it happen.

It’s not often that a company spends as much time telegraphing its intentions as Athabasca with its looming joint venture, talk that has, by one investor’s calculation, boosted its share value by some $3, a huge amount. In August, the stock jumped 12 per cent on news that the company was considering a joint venture, reportedly with the Kuwait Petroleum Corp. The promotion around a looming deal is, some say, plain weird. “They’re just odd. They’re really promotional,” says one Calgary investor who runs billions in the energy space.

And, the investor says, Athabasca’s strategy carries shades of the same. This is a company whose founding expertise is in the oil sands, but now says half of its production will be outside Fort McMurray, and fully a quarter won’t even be oil, but natural gas. “As a proper investment it doesn’t make sense to me, given the lack of clarity on its strategy and the lack of clarity on how it’s going to move it forward.”

That sentiment isn’t isolated: Athabasca went public at $18 per share. It now trades at around $13. It was one of the biggest energy IPOs in Canada. It’s also been one of the biggest disappointments.

But the skepticism that exists in markets has been at least partially balanced by those who say Athabasca’s moves outside the oil sands have given it the underpinning it needs to be a mid-sized Fort McMurray producer – a rare breed in a region filled with global energy titans. Because as it turns out, producing extra-light oil, called condensate, is helpful to a company that needs condensate so its thick oil sands crude can flow down pipelines. It is the same for natural gas, a critical ingredient in the manufacture of oil sands crude.

“I believe strongly in that integrated process. It worked for Suncor. It will work for these guys,” says Rafi Tahmazian, a senior portfolio manager with Canoe Financial in Calgary. Plus, that deep basin play? Turns out, Athabasca called it right. They got in for, on average, $150 an acre. Land there now has now traded up to $4,000 an acre. And that condensate, which Athabasca consciously chased? It sells for more than oil. It is the most valuable hydrocarbon produced in Alberta today.

“It’s either bald-ass luck or very strategic,” says Tahmazian, who has never owned Athabasca, but says it has an important role to play. “We need it to happen. There’s a definite appetite in the investor marketplace for a more aggressive growth oil sands player. And if they’re able to demonstrate that they can play in more conventional assets, that gives me significantly more confidence in the business.”

That, Tahmazian added, is already happening. This summer, Athabasca raised its 2012 output guidance by some 2,000 barrels, saying it expects to exit the year at 10,000 to 11,000 a day of production.

Or perhaps something bigger. Athabasca is barely a corporate infant, just on the doorstep of pumping its first oil. There will be all manner of opportunity for missteps and failures. There is a possibility that the company won’t last, if it falls victim to the ambitions of someone larger than itself. Bryan Gould, for example, wanted to buy Athabasca outright when he worked at Shell.

Yet Svarte says the dream is to build the company into something bigger. He already knows what he wants it to look like: Canadian Natural Resources Ltd., the Alberta oil patch wunderkind. Svarte is attempting to follow in CNRL’s footsteps by taking full control of his hydrocarbons, building pipelines and processing facilities to ensure he is not beholden to others. He, of course, has a good long way to go to narrow the 600,000-barrel-per-day chasm that divides Athabasca from CNRL. But for a man who once figured out how to turn orange berries into profit, it is perhaps understandable to hope the future brings ownership of one of the sweetest berry patches around.

“Since I started working in Canada, CNRL was my favorite company,” Svarte says. “And obviously if there’s one company I’d like to try to approach as an ambitious goal, it is CNRL. They did everything right.”

If company forecasts are to be believed, a sector that’s been built on strip mining is in the middle of a significant shift. In April, production from in situ oil sands projects averaged 750,000 barrels per day, a new high-water mark for the industry. Shane Walper, president and CEO of Red Deer-based Predator Drilling Inc., isn’t oblivious to the shift. His company has changed its focus to the oil sands from servicing shallow gas drillers as companies stung by low prices shut in production. “I think there are definitely opportunities up there,” Walper says.

That reality has caused Predator to shift its business strategy. Predator has been focused on servicing shallow gas wells since it was incorporated in 2008. The company sustained itself over the next few years with about 40 per cent of its business coming from the natural gas market. But chasing business in the natural gas space is no longer benefitting Predator, due to low commodity prices brought on by surging shale gas production in the United States. “This last year we saw the full implication of the gas market; it finally hit us,” Walper says. “We had Encana Corp., who is a big driller in the shallow gas market, that was a big part of our revenue stream and that went away last year.”

“The market we’re in is somewhat out of favor because everyone is going deeper and horizontal with their double and triple rigs.”

In 2011 only about 20 per cent of Predator’s business came from natural gas operations. Walper says the private company still increased revenue by about $3 million to $36 million at the end of its fiscal year in June. But after a 323 per cent jump in revenue between 2010 and 2011, it isn’t the growth he had planned for the company. So rather than try and win more natural gas business, Walper is sharpening his focus on northeastern Alberta.

The drilling that goes on at in situ sites in the oil sands region requires similar construction and infrastructure needed to operate in other formations. A number of companies providing services such as drilling fluid, facility construction, service rigs and site maintenance are eyeing SAGD operations, which gives them steady work and avoids halting operations during the spring break-up that occurs in Western Canada. “The biggest draw to that, whether it’s rigs or maintenance or whatever, is it’s year round,” says Mark Salkeld, president and CEO of the Petroleum Services Association of Canada.

But not all services companies in the oil sands benefit from year-round work and Predator Drilling is one of them. “The bulk of our work happens in the coring market, or delineation, and that’s all reliant on a heavy frost in the ground; so that’s all the first quarter stuff,” Walper says.

The company’s niche drilling market stems from its early days. Walper raised $15 million to launch the firm in 2008 and assembled a fleet of five rigs in five months. At the time, the drilling industry was transitioning from vertical wells to horizontal wells and small single-mast rigs were being replaced by large triple-mast rigs, which could drill deeper into the earth.

Walper took advantage of the shift by purchasing “gently used” drilling rigs at a discount from other companies. “With the downturn, cash is king and companies were looking to unload iron that they were not using,” Walper says. “The market we’re in is somewhat out of favor because everyone is going deeper and horizontal with their double and triple rigs.”

However, one man’s junk is another man’s treasure. The single rigs allowed Predator to work in the shallow gas market and step into the oil sands region performing core hole drilling, as well as drilling observation wells, disposal wells and water source wells. Predator has since added six drilling rigs to its fleet and is working on a deal to bring in another four rigs, which would put the company’s fleet at 15.

Walper is also working to bring in more business by diversifying Predator’s drilling services in the oil sands by drilling the first portion of a SAGD well, so the surface casing can be set before a large drill rig comes in to drill the well to its full depth. “We see the large diameter pre-setting as a huge market for us to increase our utilization year-round,” Walper says. “They save around $30,000 on their overall cost per well by allowing us to do that portion of the service.”

There are some risks for service companies like Predator in going after in situ business. Calgary investment bank Peters & Co. has noted the performance varies at SAGD projects in Alberta. “The results are still weaker than expected for a number of projects that have been on production for an extended length of time,” Peters warned clients in a June research note.

Walper is undaunted. His growth plan for the company includes building some of the larger SAGD drilling rigs. “Those rigs typically work 300 to 340 days per year,” Walper says. “We haven’t got to the stage yet of raising capital for that portion, but I anticipate in the new year we’ll be set up to pursue that.”

James Horvath, president and chief executive officer of Lonestar West Inc.Photograph Jason Everitt

Blasting the earth with a high-pressure stream of water, then sucking up the mess with a truck-mounted vacuum, may seem like a strange way to dig a trench.

But for James Horvath, president and chief executive officer of Lonestar West Inc., the technique makes perfect sense. If you want to move dirt, any old excavator will do. “But if you want to do any skilled excavating, a hydro-vac out-digs a track hoe,” Horvath says.

The Sylvan Lake, Alberta-based company’s skilled excavating techniques are increasingly in high demand. Horvath’s business has benefited as pipeline builders scramble to bury steel along fresh corridors from new basins. Fully 70 per cent of the firms contracts are tied to the oil and gas industry. First-quarter revenues climbed 45 per cent in 2012 to $5.8 million, up from $4 million for the year-prior period.

Lonestar has a fleet of 33 hydro-vac trucks. More than two-thirds of them are owned by lease operators. The units take a more delicate approach to excavating by washing over buried electrical, water and sewer lines, reducing the chances of a dig fouling underground infrastructure and existing pipelines at project sites.

Horvath’s company trains independent operators to run the trucks. He uses a franchise business model – Lonestar books jobs and provides administrative support for truck operators, who use the company name, in exchange for a percentage of their revenue – that is common to the trucking industry.

It means companies can expand their fleet without taking on the capital cost of buying new equipment – an important distinction, Horvath says, because a brand new hydro-vac truck can cost up to $400,000.

The business model also makes for more efficient service, Horvath says. “When a big-inch pipeline fires up, like a TransCanada line or an Enbridge line going across the countryside, it can wipe out a fleet as far as utilization is concerned,” he says.

“Having lease-operators provides more mass for Lonestar and allows us to bid on big jobs without leaving the rest of our customers high and dry.”

Horvath started in the oilfield trucking business in 2000. He moved into the excavating business not long after, purchasing a 1989 Kenworth vacuum truck for just over $100,000 to remove and dispose of drilling fluids. In August 2007, Lonestar earned roughly $3 million in revenue with a fleet of six trucks. One year later, the company debuted with a $1.2-million initial public offering.

Soaring light oil and shale gas production from new basins in the United States and Canada, plus continued growth in Alberta’s oil sands, all require new pipelines.

TransCanada Corp. was recently selected to build a $4-billion pipeline in connection with a massive liquefied natural gas project proposed for Canada’s West Coast. Transportation rival Enbridge, meanwhile, expects to spend in excess of $17 billion on new projects by 2015, according to a June investor presentation.

The hydro-vac business is “a high-growth industry today, as the whole infrastructure for the oil sands and the whole gas industry expands,” says David Prussky, a Lonestar director.

Lonestar is not counting exclusively on the oil and gas sector. It is also targeting business from companies that install utility lines, fibre optic cables and electrical power lines. “Not just in Calgary and Edmonton, but across the country and across North America,” Horvath says. “There are some other things we’re working on to diversify our customer list.”

]]>Belgacem Chariag’s accent isn’t easy to place. For the past three years he’s been the president of eastern hemisphere operations for Baker Hughes Inc. He is currently stationed in Dubai. There are only three countries between Chariag, in the United Arab Emirates, and his native Tunisia, but he’s travelled all around the world to get there. “You name it and I’ve been there,” he says.

Illustration Eddie Guy

Although born in a country that produces less than 100,000 barrels of oil per day, Chariag was inspired by the booming activity in nearby Saudi Arabia at an early age. He studied petroleum engineering at the University of Texas. Since then he’s held jobs in Europe, the Middle East, the United States and Africa.

Dan Lumma, executive vice-president of energy markets and strategy with Houston-based engineering and construction firm Kiewit, nods in agreement as Charaig speaks. The two energy industry veterans are becoming acquainted over a glass of wine at the Calgary Golf and Country Club. While working in the energy industry has allowed both of them to travel the world, this isn’t the first stop in Calgary for either one of them.

Lumma’s been with Kiewit for 22 years. He grew up in the U.S. Midwest, graduating from the University of Missouri with an electrical engineering degree. He’s been travelling to Calgary semi-regularly since 2004. “When I first came up here it was a niche market in the oil and gas business,” he recalls. That has changed. “It has become apparent Calgary is not just a niche market, it’s a critical oil and gas hub.”

“We’re going to attract the highest flyers from around the world and in a short period of time, they’ll be running companies all¬†around the world.”

The city’s rise mirrors Alberta’s ascent as a destination for global capital. That, in turn, has fueled a desire for a new class of corporate executive, one who can move seamlessly between a remote well site at Bowden, Alberta, and the gleaming towers of Beijing.

Cue the Global Energy Executive MBA program at the University of Calgary, known by its awkward-sounding acronym, GEMBA. The university’s Haskayne School of Business partnered with white-shoe consultancy IHS CERA to create the program. It gives energy executives from around the world access to an MBA program focused solely on the industry they work in. It’s also recognition that the southern Alberta city is quickly shedding its Cowtown image. “Calgary’s role is increasing in the world,” says Harrie Vredenburg, the program’s academic director.

Vredenburg says he has been pushing for an MBA program specifically tailored to energy industry executives for several years. He helped design the University of Calgary’s master-ofscience program in sustainable energy development, but he only got his wish after Len Waverman became the dean of the Haskayne School of Business, in 2008. “He sat down with a group of us and said, ‚Äòwe need to think big,’” Vredenburg recalls.

A partnership was struck with IHS CERA and Vredenburg started working with academics from around the world to develop a new program. GEMBA students will spend about two weeks on-site in four key energy markets around the world during the 16- month program. In between the learning modules, students will participate in online sessions and work with their peers through virtual discussions.

Completing an MBA program has always been a personal goal for Chariag, but it didn’t always gel with his professional role at Baker Hughes. GEMBA changed that. “The convenience to come in for two to three weeks, then do it from home and work virtually was important,” the 49 year-old says.

Part of the reason GEMBA was structured in such a fashion was the recognition that many of the students needed to stay on their career paths. “For most of these people, the next stop is the c-suite and this is the last polish they need,” Vredenburg says. “We’re going to attract the highest flyers from around the world and in a short period of time, they’ll be running companies all around the world.”

The inaugural class of 20 students is onethird foreign students and the rest are from Canada. At a welcome reception held for the class this spring, David Hobbs, chief energy strategist with IHS CERA, marveled at the experience on hand. He wasn’t the only one to notice. That some of the students are a little long in the tooth is one of the reasons Kunle Babalola was drawn to the program in the first place.

The principal partner with El-Parazim Consulting Services in Calgary completed a master’s degree in petroleum engineering at the University of Dalhousie in Halifax and then did one semester of an MBA. His fellow students were kids, he recalls. “They were all young children and I wanted a program that would fi t into my lifestyle and my ambitions,” the 40 year old says.

The larger appeal of the program, though, is its unvarnished focus on the energy industry. Vredenburg says there are other MBA programs – in Houston and Norway, in particular – that offer options focused on energy. “This is unique in that we focus only on energy,” he says. All of the case studies and examples provided by professors will come from the energy industry, so students don’t have to learn strategies implemented by Southwest Airlines or Toys “R” Us and fi gure out how to apply them to the oil business.

“I hope to be able to think more strategically and analyze things to think with a broader interest.”

That focus was enough to convert John Vicq, manager of business and commercial shale gas for Nexen Inc., into a student, despite the fact he had no previous ambitions to earn an MBA. Vicq graduated from the University of Saskatchewan with a bachelor of commerce degree and since it was pre-Bakken and pre-boom times in Saskatchewan, he headed to Alberta and joined Arthur Andersen LLP.

Most of Vicq’s clients at the accounting fi rm were in the oil and gas industry, so it was just a matter of time before the chartered accountant moved in-house. The 41-year-old has been with Nexen for 11 years and when the idea of an energy-focused MBA was presented to him, it changed Vicq’s thinking. “All of the cases, assignments and discussions will be about the industry we live in every day,” he says. “I hope to be able to think more strategically and analyze things to think with a broader interest.”

The executive training course is accredited by the Association of MBAs, but for the fi rst intake of students, at least, its credibility also comes from the Haskayne School of Business, IHS CERA and the realization Calgary is not just a hub for leading oil and gas producers in the world.

Increasingly, it’s viewed as a city that can produce leaders for the world. “When you’re in the western part of the world you know Calgary,” says Chariag of Baker Hughes. “But even in other parts of the world it’s known for innovation, entrepreneurship and technology.”

Paul Reichard tends to get a baffled reaction when he introduces oil and gas firms to his company’s collapsible FRAC Tank. “We’re seeing a lot of people raising their eyebrows,” says Reichard, the division manager of remote sites and environmental at SEI Industries Ltd., an industrial manufacturing firm based in Delta, British Columbia.

It’s easy to see why. The 190 cubic meter tanks – used to hold fracking fluid during unconventional drilling operations – are a different animal from 500-barrel metal cylinders typically used by industry. SEI’s product is a fabric-based inflatable pouch, which resembles an enormous hot water bottle.

Companies are responding to a growing industry demand to store fracking fluids. This has made transportation a challenge for operators, especially as wells get deeper and greater volumes of sand and water are required to crack the tight rock formations.

Into this market comes SEI Industries. While it has only sold 200 FRAC Tanks, it is now marketing the product all around the globe. Schlumberger was one of the first firms to purchase the tank, using it for fracking operations in Poland. The tank is also being used closer to home – in B.C.’s Horn River shale gas play. Other potential markets include Australia, Colombia, Argentina and Texas’ Eagle Ford basin.

Unlike other tanks, SEI’s product can be deflated, rolled up and repositioned as the well locations change. It’s an advantage Reichard has stressed as he pitches the tanks as an alternative to its 500-barrel counterpart, the staple product in the industry.

Another selling point is cost savings. A single flatbed truck can hold 24 FRAC Tank units – about 4,560 cubic meters of storage capacity. SEI says it could take 57 trucks to transport the same storage capacity in 500-barrel steel tanks. That means a lot less truck traffic on these roads, which landowners like, and less trucking costs – something producers appreciate. But it’s still been a tough sell for SEI and Reichard. Conventional frack tanks are still the easiest units to install.

To resolve that issue, SEI is making the rolling and unrolling of its tanks less strenuous with a new deployment system. Moving the tanks will now require one worker using a Bobcat attachment to reposition or roll up the tanks when deflated.

The initial stages of manufacturing the FRAC Tank itself were also a challenge. It was the first product SEI made exclusively for the oil and gas market. The company based its model on the Terra Tank, an SEI water-storage vessel primarily used by the military. However, the FRAC Tank quickly ruptured when pressurized – it needed to withstand a flow rate of about 100 barrels a minute – and engineers didn’t initially realize that frack fluid is often heated.

The product was launched in 2011 and the tank now features a new abrasive-resistant fabric, a more durable seam and better temperature resilience. SEI says the tanks can now withstand a -50 C climate while containing 72 C frack fluids. They are also quite compact.

Nevertheless, the product has been dogged by worries of its dependability. Convincing prospective companies the tanks are safe from abrasions will take time, Reichard says.

“They’re afraid they’re going to be able to walk up and cut this thing and puncture it,” he says. But Reichard says holes can be patched up like any other water frack tank. He points to SEI’s military grade tanks as an example of how tough these things are. “I’ve got tanks in combat situations where they’ve got bullet holes all over them – they’ve got these plugs all over them – and that’s just the way they operate.”

If Alberta’s oil sands development were compared to a dog fight, Surmont Energy Ltd. would be the comically undersized pit bull. With only a handful of employees, the junior oil company is pursuing a gutsy drilling project in the heart of oil sands country, 70 kilometers south of Fort McMurray. Surmont is currently in the midst of a core sampling program. It hopes to have a full-fledged steam-assisted gravity drainage (SAGD) operation in place by the summer of 2013.

Making a go of it in the oil sands is an undertaking usually left to Big Oil. Surmont is surrounded by constant reminders of its size disadvantage, with ConocoPhillips, Nexen Inc. and Statoil ASA located mere kilometers from its 19 sections of land totaling 12,000 gross acres. But Surmont CEO Mark Smith says the risk is well worth it.

The privately owned company has farmed into the 19 sections under Bounty Developments Ltd. for an 80 per cent interest stake. It hopes to be producing between 10,000 and 12,000 barrels of oil per day by 2014. It’s an ambitious goal for a small company with no production, but the company has embarked on a $6-million drilling program where it will extract 12 core samples. “We’re trying to squeeze two seasons into one,” Smith says. “It’s been extremely exciting.”

Forays into the oil sands are not for the faint of heart. The resource is huge but it’s also expensive to develop and high oil prices – in the US$70 and above range – are required for most projects to be economic. Still, the potential to make profits has been luring entrepreneurs to northern Alberta. The ability to tap 170 billion barrels of oil sands reserves has piqued the interest of investors, who are drawn to firms operating in Alberta’s bitumen belt that offer the potential of attractive payouts, even if they have a comparatively small grubstake.

Smith – along with his three other counterparts Bill Cooper, Gordon Holden and Leith Pedersen – recently completed a 3-D seismic program on four of the sections. Since November they have pushed the project forward briskly. In a whirlwind four months, the owners managed to collect $11 million in capital strictly from family, friends and business associates.

“What I’m surprised by is the amount [of capital] available for the right projects. I think this is attractive; it appeals to a lot of people,” Smith says. That figure would have been closer to $16 million, if not for an unexpected fallout with a Houston-based investment fund that backed out during the final stages of the deal in February.

Those struggles come with the territory, Smith says. Still, the odds of succeeding in a high-cost business like the oil sands are long. Regardless, the four directors are quite comfortable having the odds stacked against them. They have plenty of experience working together. In 1996 Smith worked as CEO for Scimitar Hydrocarbons Corp., a Calgary-based producer with operations in the United Arab Emirates, Egypt, Mozambique and Western Canada.

Holden was the chief operating officer at the time and Cooper was a resource investor. The company was doing similar work there, drilling on then-unproven reserves. But was it as risky as Surmont’s current exploration? “It was different risk,” Smith says. “We had country risk when we were dealing internationally, which you don’t have here.”

But if history is any indication, Surmont stands a chance of success. Scimitar was producing around 1,000 barrels of oil per day when Smith left it in 1998. In 2002, it was struck a deal to merge with Rally Energy Corp. for $900 million.

Marc Breault, president of Paradox Access SolutionsPhotograph by bluefish

For years, there was very little to think about when it came to accessing well sites. When oil and gas companies needed to enter isolated lease land, the solution usually involved a heavy truck or a bulldozer. “They used to be able to blade everything to the sub-structure,” says Marc Breault, president of St. Albert-based Paradox Access Solutions Inc. “They love to rip, tear and destroy.”

But things are done a bit differently in 2012. As government regulations become more rigid, and the penalties for breaking them more severe, producers have to access well sites using as little brute force as possible. That has led to business opportunities for Paradox. The firm entered the market in 2004, and has since evolved into a growing mat supplier in Western Canada. Its portfolio stretches from British Columbia’s Horn River basin to the southwest tip of Manitoba in the Bakken.

Breault distributes his mats from nine warehouses located around Alberta and Saskatchewan, with a total inventory of more than 30,000. His client base is quite broad, and includes heavy hitters like Enbridge Inc., Imperial Oil Ltd. and Shell Canada. As horizontal drilling practices drag producers into more isolated lease sites, Breault has watched interest in his mats swell. “They hate them, but they know they work,” he says of exploration companies. “We get a lot of companies into places they shouldn’t be able to get into.”

In 2011 Paradox tripled its revenue, up to $30 million from $9 million one year prior. The secret to its growth may be its diverse, and different, products. Unlike typical mat suppliers who use softwood lumber, Paradox’s inventory consists of matting made of rubber, bamboo, plastic and fiberglass. Paradox’s manufacturers are scattered around the globe. Breault goes to Chinese suppliers for lightweight bamboo mats, the United States for kiln-dried Emtek wood mats and to the Middle East for the mesh-like Neoweb matting.

While the products bear strange names, unorthodoxy is Breault’s mantra. Government regulation has been a major part of the company’s quirky product base, he says. Before starting Paradox, Breault worked as a site access consultant for the oil and gas sector. At these jobs he saw companies were failing to consider the increasing restrictions on land disruption and pipe crossing on site.

His first product was rubber matting made from recycled car tires. It was a tough sell. His mats cost producers $10 per day, while the traditional wooden mats ran companies about $3. Customers keen to keep capital budgets low and use mat products they are familiar with continues to be an issue for Paradox. The greatest challenge for Breault is convincing customers that he offers a long-term, cost effective product. Traditional mats retain heavy amounts of water and mud, he says, making the cost of trucking them off site far more expensive. “You have to look at the whole picture,” Breault tells his clients. He estimates trucking accounts for 60 to 70 per cent of the cost of using mats at the site.

One of Paradox’s newest and more interesting products is a highly buoyant polypropylene material made by All Terrain Road, an Edmonton-based company, capable of keeping heavy vehicles afloat on its fiberglass casing. The technology makes otherwise impassable regions passable for longer periods, Breault says. But initial tests for the floating mats didn’t go smoothly. “The first time we took it out onto the field it fell apart,” he says. Since then improvements have been made and the technology has been used by the likes of Syncrude and AltaLink for massive projects.

His latest product, which he started selling in 2010, also shows promise. Manufactured by PRS Mediterranean, Neoweb is honeycomb-shaped matting that is laid flat and filled with sand, gravel or dirt. The granules hold the matting to form while a steamroller compresses it to make an instant roadway. The technology was originally employed by the U.S. military to access hard-to-reach places (it used Neoweb in the 2003 capture of Saddam Hussein with a stealthy attack on the village of ad-Dawr, Iraq).

For Breault and Paradox, providing a host of mat options for clients has paid off, because conditions can differ depending on the region operators are working in. “There is no one solution that solves all problems.”

Since the job of running a company typically doesn’t fall into someone’s lap, the people who eventually sit in the CEO chair are usually the ones that look and act accordingly – and it doesn’t hurt to start practicing early. “It’s really a mindset. These are people that really want it and they focus with a ferocious resolve,” says Allen Snart of Western Management Consultants.

The Edmonton-based business consultant says focusing on a senior management position will lead to tough choices. It might mean taking a job you don’t want, but which will give you valuable experience. It also might mean turning down a glamorous job if there’s no light at the end of the tunnel. “Ambitious candidates are always thinking strategically,” Snart says.

When it comes to the traits of people who are strategically planning their career trajectory, there are plenty of shades of grey. Assertiveness and confidence can be perceived as arrogance and stubbornness when not sprinkled with the right amount of humility and integrity. “People with humility don’t think less of themselves, they think of themselves less,” Snart says. “The truly successful leaders have integrity and they’re whole people. For the oil patch this is important because so many decisions come under public scrutiny.” Volunteering with a not-for-profit organization or for a board of directors can be helpful, while getting involved in sports or arts in the community can also broaden experience.

It may sound like a lot is involved, but as Bonavista Energy Corp. CEO Keith MacPhail points out, there isn’t just one thing that will get someone to the top. Hard work is important, but passion and a keen interest in the work are also essential. “A thirst for knowledge helped me,” MacPhail says.

It took MacPhail more than a decade before he earned his first chief executive position, taking the reins of Bonavista in 1997, which brings up another aspect that can’t be overlooked: patience is a virtue. Tim Marchant, professor of strategy and energy geopolitics at the University of Calgary’s Haskayne School of Business says, “it could take 20 to 25 years to groom someone.”

For those with a yen for life in the CEO role, here is some advice from experts in the field on how to make it happen.

Stay in School

“By and large, our industry is run by technical people and it’s a technical industry, so that type of education opens a lot of doors,” says MacPhail, who leads the Calgary-based intermediate company that produced 67,900 barrels of oil equivalent per day during the first three quarters of 2011. “When I think of many of my peers, they have equivalent education backgrounds with undergrads in science or engineering.”

Education is a vital component in becoming the top executive in the energy sector. Obtaining an MBA isn’t manditory, but it can signal interest in general business and equip a candidate with decision-making skills. “It will provide the fundamentals and if you want to get good, it helps to learn it right,” Snart says.

While a technical or professional educational background will provide the base, learning additional fundamentals are what will allow someone to move up in a corporation. “Somebody has to have a single strong skill set, whether it’s an engineer or accountant or lawyer, and the people that stand out are the ones who develop skills to complement those,” says the University of Calgary’s Marchant. “Engineers have the analytical skills, but they need to learn contracts, organizational structures, human resources and people management,” he says.

Get it Done

Book smarts and formal education are a good start, but learning on the job and an inquisitive nature will bolster that technical background and help when seeking promotions. “The best education is learning by doing,” says Alan Cadotte, president and CEO of Calgary-based Newalta, which provides oilfield waste recycling and recovery services. “How do you know due diligence on acquisitions? You do two or three of them.”

In 10 years with Tricil Ltd., Cadotte was able to learn all aspects of the business and he gained experience in managing capital budgets, environment, health and safety, human resources, marketing, due diligence and integration of acquisitions. Cadotte was actually working on integrating assets Tricil had acquired from Newalta in 1993 when it offered him the CEO post. “While I was grinding them away at the deal, they offered me the job,” Cadotte says.

It was his first chief executive job and it took more than a decade to reach, but becoming a CEO was something Cadotte worked towards. “I didn’t focus on the CEO job, I just tried to learn skills required to run a business,” he says. “I went from head office to operations and that was a bit of a demotion. You have to be prepared to move laterally and take jobs for the learning experience, not just for money. If you have to take a step down, that’s fine. You don’t have to progress up the ladder like it’s a ladder.”

While learning new skills and different aspects of the energy business will keep a career on an upward trajectory, it will also provide better perspective when you reach the top. “A good leader is somebody who can get down in the trenches and work with anybody, but also elevate themselves and see where things are going two years down the road,” MacPhail says. “A broad knowledge base is critical for a successful CEO to understand everyone’s role.”

Asking for It

While taking on new projects will provide valuable work experience, not every task will be exciting. It’s hard to be passionate and work hard on an assignment you don’t want, so be proactive and ask for assignments in areas of interest.

“You have to tell them, ‘my initiative will create value in this way and I think I’d really enjoy it,’” Cadotte says. “I was inquisitive and restless, and would propose assignments and projects I could work on. I would say, ‘I want to do this, but I’ll need support.’ If I waited for my boss to give me work, I’d still be doing the same job today.”

Of course, if you say you’re going to deliver value, then you better follow through. “Being a good leader is all about other people’s confidence in your ability to do what you say you will. That’s what people recognize and that’s what they reward,” Marchant says. “A person who leads right through to the end of a project and maintains excitement can be thought of as a leader. They’ll say, ‘she made it happen, let’s give her a bigger project.’”

And if you want to pick that next project, start planning for it once you begin the current project. “Don’t do anything in two years that you’re doing today. Someone told me that early on and it stuck with me,” Cadotte says. “Start tomorrow getting rid of stuff and your job should totally transfer in two years.”

Follow the Leader

“Having a mentor is a very critical piece to the puzzle,” MacPhailsays. “I was very fortunate through most of my career to have one or two of them to help and look out for me.”

Sometimes, it doesn’t even have to be a formal mentor relationship to be a learning experience. “If you want to develop good leadership skills, poke around a bunch of leaders and learn from them,” Cadotte says. “I was always a bit like a sponge. You observe, take note and some of the skills you try to adapt. But you have to work it into your own style. It has to be natural.”

For every additional rung in the corporate ladder, there are additional responsibilities, so when you get to the top there will be a pretty hefty pile of obligations waiting. While it’s important to delegate tasks, Cadotte says there are certain things that the CEO has to take care of and if you don’t manage your time properly it’s easy to lose your way. “It’s a constant struggle,” he says. “I do a pretty tough review once a quarter to make sure I’m on track.”

With meetings scheduled every half hour, keeping on track is a priority, especially when there are dozens of topics to cover in a day. “You have to make decisions; that’s why they come to you,” Cadotte says. “Say you can’t multi-task. You have to focus on each task and be able to turn things on and off to give 100 per cent attention.”

The ability to face multiple questions on multiple topics in a short period of time is one area where studying for an MBA could come in handy. “By using case studies, students are given an awful lot of information. A student rarely has time to understand all the nuances, but they have to make decisions,” Marchant says. “Technical people are taught that if you study it more and get more data, you’ll get a better answer, but as you rise up the ranks you’ll find you won’t always have all the data. It’s about being able to make decisions in the face of uncertainty.”

The Buck Stops Here

MacPhail held a series of senior roles prior to becoming CEO of Bonavista Energy. At 29, he became general manager at one of the smaller business units of Poco Petroleum. He later got hired on with Canadian Natural Resources Ltd. (CNRL) and progressed up the ranks, ending up as executive vice-president and COO.

“The biggest shock for me was to come to grips with where the buck stops and that’s with the CEO. Even in my time at CNRL, which was almost nine years in a very senior position, there was always someone above me I could go to,” MacPhail says. Most employees are aware that nobody is perfect. Employees expect their CEO to provide guidance and a vision for the company, so they can focus on their daily tasks. “You never want to go out on a limb and take chances,” MacPhail says. “But you can’t be right 100 per cent of the time.”

Making decisions is easier when an executive surrounds themselves with the right people. Nobody can do everything by themselves, and as well as making better choices, being surrounded by smart people will also help with that quest for knowledge. “Skill development for CEOs is ongoing, even today I’m learning,” Cadotte says. “When you become CEO, you’re not done.”

Click here for more advice on how to reach the top in your organization.

The decision to start manufacturing steel pipe out of a modestly sized warehouse on the southeastern outskirts of Edmonton was anything but conventional for Bri-Chem Corp. After all, the Acheson-based wholesaler of drilling fluids and, through subsidiary Bri-Chem Steel Corp., steel pipe, tubing and drill casing, didn’t initially have access to a mill.

No matter. Officials at the company ordered one from China. They partnered with Wuxi Huayou Special Steel Co., a Chinese manufacturer based in Jiangsu Province, early last year to create Bri-Steel Manufacturing Inc. Bri-Chem brought the sales and marketing expertise; with a 30 per cent share in the new company, Wuxi contributed equipment, training and engineering know-how related to the firm’s novel thermal expansion manufacturing process.

The decision seems to have paid off. In June, just six months after the partnership was announced, Bri-Chem shares began trading on the Toronto Stock Exchange. By November, the firm was trading at $3 and change, at the high end of its 52-week range.

Bri-Chem chief financial officer Jason Theiss says the jump from wholesaling to manufacturing pipe fits with the company’s long-standing emphasis on doing more with less. Sales from the pipe mill topped $182,000 through the third quarter of 2011, a token amount compared to the $7 million in quarterly sales earned overall by the steel division. While it works to secure sales for 2012, the firm is predicting a strong performance – based on a forecast 16 per cent increase in fourth-quarter drilling activity in Western Canada – from its fluid business.

Bri-Chem began wholesaling drilling fluid in Western Canada in 1985 via a subsidiary called Bri-Chem Supply Ltd. The business was simple: buy drilling fluid products from manufacturers and resell them to the oil and gas industry. The firm boasts 17 warehouses spread throughout the Western Canadian Sedimentary Basin, from the remote reaches of the Horn River shale gas formation east to the sprawling Bakken “tight” oil play in Saskatchewan. The idea, Theiss says, is to supply “the right product at the right time.” Clients today include Trican Well Service, Canadian Energy Services LP and CCS Energy Services.

Steel is a comparatively new venture. In 2008, Bri-Chem paid $10.9 million for Weifang Steel Canada Ltd. and began wholesaling steel pipe to complement its fluid sales. The purchase proved to be a shrewd way to offset seasonal fluctuations in drilling activity. “When we looked at that acquisition back in 2008, it was a very similar type of business model [to the fluid business] – low employee count, low overhead, highly efficient, very scalable operations.”

Today, the mill acquired via the Wuxi partnership produces four to six truckloads of pipe per day ranging from 14 to 36 inches in diameter. The novel thermal expansion process involves heating the pipe to around 650 Celsius and expanding it to a previously calibrated size. The end product is a “seamless” tube that requires no welded joints. Theiss expects the mill to operate at full capacity this year. He says the process will yield 10,000 and 15,000 tonnes of large-diameter product annually.

Manufacturing pipe in-house has another advantage. As a wholesaler, Bri-Chem regularly dealt with damaged pipe imported from abroad. “The problem with large-diameter pipe is you can’t store it in a boat very easily and you can’t ship it overseas very easily,” Theiss says. “It’s got to go bulk. It can’t go in containers, so it bounces around.”

Fluid sales are still an integral part of the business, posting $53 million in third-quarter sales. Fluid consumption has been on the rise across North America, Theiss says, as companies adopt advanced drilling techniques to tap new geology. “What we’ve seen in the past years, the well count isn’t high, but the meters drilled have been a lot deeper, a lot longer, more horizontal, which consumes a heck of a lot more fluid for us,” Theiss says.

Acquisitions continue. In June, Bri-Chem paid US$2.5 million for Denver, Colorado-based Stryker Ltd., a transportation and fluid distribution company. The purchase fits with a U.S. expansion strategy to build a distribution business aligned with activity in unconventional resource plays from Texas to the U.S. northeast in Pennsylvania. “Breaking into the U.S. market is a lot more of a challenge,” Theiss says.

Left to right: Glenn Leroux of BOS Solutions; Jim Rakievich of McCoy Corp.; Randy Hawkings of CanElson DrillingPhotograph by John Gaucher & Bluefish

Operating in the western canadian Sedimentary Basin is nothing if not cyclical. The high peaks of activity are often offset by steep valleys and remaining profitable for 12 calendar months is no easy feat, let alone doing it year in and year out. “If you want to grow and not be cyclical, you have to step outside of Alberta,” says Jim Rakievich, president and CEO of McCoy Corporation, which manufactures drilling and completions equipment.

Stepping out of Alberta and into the American oil and gas market is a logical destination to expand a firm’s horizons. Proximity makes it less expensive than moving operations to the Middle East or Eastern Europe and familiarity with the culture should simplify learning the business environment. But the sheer size of the U.S. might be the best reason to look there for new business opportunities. According to the International Association of Drilling Contractors, the rotary rig report for the first week of October had 2,012 rigs in the U.S. compared to 522 in Canada. “The U.S. has the largest concentration of rigs in the world,” Rakievich says. “Globally it’s an important market.”

At the very least, the American oil and gas industry can serve as a proving ground for expanding into other foreign markets. “If you can’t expand into the U.S. and be successful, you can’t go to a more sophisticated and higher risk region and be successful,” says Glenn Leroux, president and CEO of BOS Solutions, a fluid management company that has been operating in the U.S. since 2007.

Below is a snapshot of three companies whose move south has paid dividends.

McCoy Corp.

McCoy Corp. CEO Jim RakievichPhotograph by John Gaucher & Bluefish

The Opportunity

Founded as a blacksmith shop in Edmonton back in 1914, McCoy specialized in forging a variety of different steel products during the ensuing decades. At one point, McCoy was contracted to manufacture hydraulic tongs for use in the oil patch. It seemed like a promising business line, so McCoy acquired the company that developed the product 15 years ago.

Although McCoy had entered the oil industry, it wasn’t the company’s main business. Just four years ago, McCoy relied on the trucking industry to pay most of its bills by manufacturing parts for truck and trailer repairs. “We owned a truck dealer in Grande Prairie,” Rakievich says. “The majority of our revenue in Alberta came out of the repair shops and selling replacement parts.”

Despite the company’s diverse business lines, Rakievich saw the greatest potential for growth in oil and gas. But the majority of McCoy’s drilling and completions customers were not in Alberta, but headquartered in the southern U.S., which is also where the competition was located. “Our competitors were down there operating on the ground, which gave them an advantage,” Rakievich says. “If we were going to be a serious player we needed to have a presence in the Gulf [Coast].”

The Strategy

Rakievich says McCoy had two main competitors: a company in Texas and a company in Louisiana. “If we could acquire one of those companies, we’d become market leaders and have a footprint in the U.S.,” Rakievich says. In 2007, McCoy did just that, purchasing Louisiana, Lafayette-based Superior Manufacturing and Hydraulics. At the time, Superior was doing $28 million in sales and Rakievich says the two companies only competed in about 30 per cent of their products. “It was a good fit and made more sense,” he says.

Re-branding the two companies under the McCoy umbrella was the biggest challenge. It was one thing to gain Superior’s market share, but keeping it would be more work. “Who the hell is McCoy in Louisiana? It was a challenge not to lose business and have customers understand the switch,” Rakievich says. “We did it methodically and communicated with our customers. We trained the sales people and everyone on the communications strategy and that has to be well thought out.” Superior’s management team also remained with McCoy to help with the transition. “They’re still there and it’s tremendous,” Rakievich says.

The Payoff

“It’s exceeded my expectations,” Rakievich says. “We always said if we were going to do it, if we achieve one thing, it would be to take out a competitor, get a footprint and maintain revenue – that was the minimum. We brought more capital and we’ve grown the global business.”

In 2006, 84 per cent of the company’s revenue was created in Canada. By 2010 it was 47 per cent. McCoy maintains its corporate headquarters in Edmonton, but the company has added a sales office and warehouse in Houston to complement the manufacturing facility and office in Louisiana. As well as adding to the company’s oilfield manufacturing business, McCoy sold off some of its other business lines.

The majority of its business is now focused on manufacturing drilling and completions equipment. “We’ve really been transformed,” Rakievich says. “Getting into the U.S. allowed us to build that part of the business. It confirmed that the transformation made sense and got us committed.”

BOS Solutions

BOS Solutions CEO Glenn LerouxPhotograph by John Gaucher & Bluefish

The Opportunity

BOS Solutions built its business primarily on a system that manages drilling fluids and waste created during the process. “The core thing is we dispose of the need for a waste pit on site,” says Glenn Leroux, president and CEO of BOS. While the number of drilling pits across Western Canada has been reduced, in the U.S. those pits still frequently dot the landscape. “We could see growth limitations in Canada and the management team decided that it was time to get a foothold in the U.S. and become a North American company,” Leroux says.

BOS started looking at states where the oil and gas industry was flourishing and where the residents had a fairly strong environmental consciousness. The Calgary-based company picked Colorado. “It’s a wise and logical step,” Leroux says. “It costs about $10,000 to truck our system down to Colorado, but it would cost hundreds of thousands to get it to other places in the world.”

The Strategy

Once BOS decided on Colorado, the management team went down and started surveying drilling sites. “They just started driving around,” Leroux says, who joined the company in 2008. “They took a couple of systems and put them on a truck. It was a bit of a gamble.” The company did find work on a drill site and started shopping for office space shortly after, opening a small facility in Grand Junction, Colorado in 2007. “We weren’t just flying through and needed to establish ourselves permanently,” Leroux says.

The biggest obstacle facing BOS was finding people, a challenge Leroux says still persists. “Which is bizarre in a country with nine per cent unemployment,” he says. BOS established a training center and one of the company’s four executives spends time with each group of trainees in an effort to help establish the company culture and maintain it as the firm grows its American business. The U.S. has become such an important market for BOS that Leroux figures 15 to 20 per cent of his time in 2011 was spent stateside. “Quite honestly, I probably should spend more time down here,” Leroux says. “Our COO spends twice as much time as I do in the U.S.”

The Payoff

“Has it paid off? Absolutely,” Leroux says. During its first year in the U.S., BOS peaked at 17 jobs and the timing of the move was also significant. “Things were collapsing [in Canada] and we just moved the equipment south,” Leroux says. “It was a lot to handle, but we managed to do it.” BOS has since found work in 10 states and regional offices have been established in Pennsylvania, North Dakota and Texas.

After four years, the majority of the company’s revenue is now derived from the U.S. Leroux says about six months ago that would have meant a 60-40 split, but with the resurgence of horizontal drilling in Western Canada that margin has been somewhat reduced. BOS’s success in the Centennial State also caught the attention of a private equity firm, which purchased BOS in October 2010. “That gave us capital we did not have access to before,” Leroux says. He says the company hasn’t stopped expanding. “We’ll grow like hell,” he says. “We grew our U.S. business during the downturn. There are more influences on our growth than just rig counts.”

CanElson Drilling

The Opportunity

Launching a company can be a challenge at the best of times, but as the price of oil dropped below US$40 per barrel at the tail-end of 2008, getting into the drilling business must have seemed like an especially tall order. The founders of CanElson Drilling Inc. were undeterred. “The market was pretty weak in late-2008 and all of 2009,” says Randy Hawkings, president and CEO of CanElson. “Having said that, good rigs with good crews still work.”

The Calgary-based drilling company deployed its first rig in December 2008 in Alberta and a second rig followed a month later. The fledgling company started looking at expanding into the U.S. early. It was out of necessity – an effort to offset the impact weather often has on drilling in Western Canada and on a drilling company’s bottom line. “We were actually looking at North Dakota because of its proximity to southeast Saskatchewan,” Hawkings says. “The Bakken is a big opportunity because it is similar to the Western Canadian Sedimentary Basin. In Texas the big attraction is year-round work. They don’t have break-up like we have here.”

CanElson was looking at establishing a U.S. presence in other resource plays as well, but in the end Texas won out. The drilling company deployed its first American rig in the Permian basin in December 2009.

The Strategy

Business can often be about whom you know, not what you know, but CanElson’s expansion into Texas was a little bit of both. “I expanded into the U.S. with a private corporation [Western Lakota] in 2006 and for the first eight months of 2008, I worked for a Texas oil company as a drilling engineer,” Hawkings says.

He left that company and was one of four people to invest the seed money to start CanElson. His previous employer asked Hawkings if CanElson was interested in bringing some rigs down to Texas. Since Hawkings was familiar with the company and the Permian basin, it was an easy expansion to make. In fact, the expansion was simple enough that CanElson added a second drilling rig in Texas one month later, while adding two more in Alberta, for a total of four rigs in the company’s home province.

The Payoff

“West Texas provides us with the opportunity to work year round and smooth out the peaks and valleys of our cash flows,” Hawkings says. A year and a half after CanElson expanded outside of Alberta’s borders, the company’s rig count jumped from two to 28. It’s now operating in a number of different regions, including Texas, Alberta, Saskatchewan, Mexico and, with the $24-million acquisition of Redhawk Drilling in June, North Dakota.

The company now has four regional offices spread around North America and a range of contracts that provide much needed capital in lean and flush times alike. “In Texas we have performance-based drilling contracts where we get paid by the foot. The more you drill, the more you make,” Hawkings says. “There are some contracts like that in Canada, but it’s nowhere as prevalent.” CanElson’s strategy is to keep growing, continuing to build new rigs, as well as acquire other rig companies that are for sale – if the deal makes sense.

Now that you know what it takes to thrive in the U.S., read these tips on how to expand abroad.

Brad Wanchulak, left, and Cliff Wiebe of storage specialist Poseidon ConceptsPhotograph by James May

Brad Wanchulak has always been a small-town guy. He comes from the town of Edson, about 200 kilometers west of Edmonton. And while his company, Poseidon Concepts Corp., is going through rapid expansion, he plans on keeping his business simple. “As we grow as a big group we’re still going to be a small company at heart,” says Wanchulak, the senior vice-president of global development. “We’re small town guys. We’re going to run it like a small business.”

Until early November, Poseidon Concepts was a division of Open Range Energy Corp., supplying fracking fluid storage tanks to the company to cut costs in fluid management. Poseidon split from Open Range this fall. Shares for the standalone Open Range jumped 48 per cent following the announcement in September.

Poseidon’s Wanchulak hopes the spin-off will paint a clearer portrait of growth plans for Open Range as it accelerates development of its Ansell and Sundance property, where management is targeting production of 6,200 barrels of oil equivalent by year end. “It’s not typical at all,” Wanchulak says of the spin-off. He thinks it can be repeated. “In our opinion it’s a model that might not work all the time, but I think it’s something producers are going to start looking at as being a benchmark.”

Poseidon, which began paying a monthly dividend of nine cents this month, specializes in fluid storage for unconventional oil and liquids-rich gas plays – prized commodities being chased in basins across Western Canada by Calgary mainstays like Encana Corp. on down to smaller outfits like Open Range.

The holding tanks, which range in size from 1,440 to 6,500 cubic meters and can hold between 9,000 and 41,000 barrels, respectively, play a critical role in the new drilling landscape as giant reservoirs for frac fluids in remote locations. Unlike the typical 400-barrel fluid storage tanks, Poseidon’s tanks can be dismantled and brought to well sites in one or two truckloads, significantly reducing truck traffic into and out of well sites.

A single Poseidon tank has around the same capacity as 48 conventional holding units, which require somewhere around 24 trucks to be transported. “From an environmental standpoint, there are fewer trucks on the road, so they’re using less fuel,” Wanchulak says. “They’re on lease roads, so the more they’re going up and down there, the more environmental impact it’s going to have on the ground.”

Insulated walls and specialized heating systems make the units more resistant to freezing in the winter months and keep the fluid around 30 degrees Celsius. The bulk of Poseidon’s business is in the United States, in shale gas basins ranging from the Marcellus in the east to the Eagle Ford tight oil play in Texas, where replacing lined pits traditionally used by operators to store wastewater at large frac jobs represents a significant growth opportunity.

Wanchulak is a former business developer for Talisman Energy Inc. He credits Poseidon Concept’s chief operating officer, Cliff Wiebe, for engineering the storage vessels. “We’ve got a great guy in Cliff, who’s an absolute wizard on developing new projects,” Wanchulak says of his colleague.

The tanks are designed to be assembled quickly using a locking system rather than bolts or latches. A typical setup takes roughly 18 hours, compared to a two-to-three day setup for 400-barrel tanks. Poseidon’s units, which resemble above-ground swimming pools, also use a single piping system, meaning they don’t have to be individually tied to a central manifold. Assembling the holding tanks was a challenge for the 15-employee spin-off venture. “Early on, we didn’t have the foundation there to be able to support the work. We didn’t have crews there to go out and set these up,” Wanchulak says.

Alberta’s Energy Resources Conservation Board (ERCB) has recognized that storage systems are evolving. In October, the agency classified the so-called C-ring storage reservoirs as aboveground synthetically-lined wall storage systems. Regulators are currently seeking feedback from industry into how the storage units are used. Officials hope to finalize new requirements within the first quarter of 2012. Wanchulak expects the outcome will be positive. The ERCB, he says, is “very in tune to what producers want to do, and they also have to consider what’s best for everybody outside of the industry.”

Current plans call for expansion into the U.S. market. With a tank fleet of 170 units, Poseidon estimates it has a five per cent share of the North American market for horizontal drilling. Capturing another five per cent would mean nearly doubling the number of tanks to roughly 330, assuming an average rig utilization rate of 90 per cent.

Wanchulak is confident Poseidon can thrive as a standalone outfit. More than 50 per cent of forecast wells drilled this year are estimated to have been horizontal in nature, and drilling programs are growing more complex. “In the end, 400 barrel tanks are never going to go away,” he says. “The volumes are increasing – the whole system has changed. And I think we’ve actually been able to capture that mindset, that things are changing, and the tank has grown because of it.”

Michael von Hauff admits he’s never had much hands-on experience in Alberta’s oil and gas sector. The only time the 32-year-old ever spent on site was during a four-month summer job with Encana Corp. while attending computer engineering classes at the University of Calgary.

But that isn’t keeping the president of Calgary-based Osprey Informatics from making a spirited business pitch to a notoriously risk averse industry. “I don’t think there’s shyness toward new technologies, but from what I understand there’s a shyness in engaging with new companies, because there’s always the chance the company will fold before its revenue is really stabilized,” von Hauff says.

Along with his 27-year-old partner Lukasz Skalka, von Hauff spent the better part of a year creating a video surveillance system, engineered specifically for remote oil and gas wells in Alberta. The surveillance cameras allow operators to monitor these sites for leaks or intruders on mobile devices, rather than in person.

The question is whether companies need this technology in the first place. A spate of unsolved bombings that hit pipeline installations in northwest Alberta and British Columbia nearly three years ago might suggest that they do. Even if only a handful of operators decide that remote-site monitoring is worthwhile, Osprey stands to benefit. Alberta alone has more than 160,000 wells in operation across the province.

The company works out of a small and cluttered lab in Calgary. Cables of different sizes run along the floor, and hardware, computers and cameras sit in crowded heaps on the desks. “Right now, it looks like a mad scientist’s office,” von Hauff says.

New digs could be in the works, though, provided a pilot project for the firm’s new surveillance technology is successful. A junior drilling company has agreed to let the duo test their product at two of its well sites near Red Deer. Osprey plans to invite interested companies to both sites for a first-hand glimpse of the system in operation.

The cameras, protected by weather-proof casing and powered by solar energy, are equipped with sensor technology that can detect movements and send snapshots to an operator’s mobile device, giving an instant view of the landscape. That allows those operators to “prioritize which well site they go to, by looking at the visual information that they get back,” von Hauff says.

The idea for the gadgets is loosely based on a surveillance system piloted by Calgary police and von Hauff thought there was an application for the technology in the oil and gas industry. “The idea was percolating in the back of my head for quite a long time,” he says.

Design work on a prototype camera began in October 2010. “We totally bootstrapped,” von Hauff says of the company’s short evolution. “We used revenue that was brought in by doing consulting to pay rent and pay our own cost of living.”

Despite the technology’s complexity, von Hauff says it is user-friendly. “The key was that it has to be very friendly to the work flow of a typical field operator. They have to be comfortable using it.” It would also cut the amount of labor needed on-site, as operators could scan for vandals, intruders or leaks using a single device.

Business has so far been slow. The upstart company has yet to secure firm contracts, yet von Hauff isn’t troubled by the response. It’s early days, he says, and there’s a demonstrated need for site-specific monitoring. “Although people have said oil and gas is really hard to break into – and I don’t have any proof to say that it isn’t – what I’m seeing so far is such strong interest in our product that we’re not going to have that issue.”

Not that Osprey’s first year of business was all smooth sailing. There were times when the project seemed it wouldn’t get off the ground. “Sometimes there are the slower months when you’re not getting the kind of feedback you’re looking for, whether it’s from vendors who are supplying you with critical equipment or you’re expecting a call from a potential client.”

But he says that’s all part of being an entrepreneur, whether it’s in the oil and gas industry or not. “I would say that in general, starting up a company just by itself is very painful. It’s exciting and fun and everything, but there are a lot of challenges.”

Those challenges have proved difficult for the fledgling company, especially during the final stages of production. “When we were trying to secure the pilot site, we didn’t know for a while whether it would go through, so that was kind of nerve-racking,” von Hauff says.

A training program run by the Prairie information, communications and technology incubator, TRLabs, provided the two entrepreneurs with the office space to work, as well as access to most of the equipment they needed to design the system. Without that funding support, von Hauff says the project would have taken far longer to manufacture. Osprey has time on its side to lure potential buyers. The question now is whether or not those companies are hungry enough to bite.

Peyto Exploration and Development Corp. president and CEO Darren GeePhotograph by Bryce Meyer

Weak natural gas prices haven’t stalled Peyto Exploration & Development Corp. Instead the opposite has happened, with low prices directly contributing to the Calgary-based company’s success. Peyto, an explorer and producer of natural gas in Alberta’s Deep Basin, has bucked the industry trend and managed to stay profitable while predominantly chasing natural gas properties. “We tend to build aggressively at the bottom of the commodity price cycle and less aggressively at the top of the price cycle,” says Darren Gee, president and CEO of Peyto. “It’s a very counter-cyclical strategy to try to take advantage when everybody else can’t.”

As persistently low gas prices force blue-chip companies like Encana Corp. to hive off midstream assets and pare down production portfolios, smaller firms like Peyto are also getting creative. With just 34 employees, an enterprise value of $3 billion and current daily production levels of 35,000 barrels of oil equivalent (boe), the company doesn’t have the staff or resources to diversify its operations like bigger players in the energy sector. Nor is it relying on joint venture spending to drive drilling activity in the current low natural gas price environment. Instead, it has focused almost exclusively on natural gas production from Alberta’s Deep Basin.

The strategy is turning heads. A recent analysis by Peters & Co. singled out Peyto as a company with a premium valuation that is likely to deliver above average growth rates. Those findings were based on natural gas-weighted entities that have the best combination of exposure to liquids-rich natural gas drilling, high production growth and strong balance sheets.

Gee is quick to attribute his company’s success to one simple factor: low costs. The company has some of the lowest operating costs in the Canadian energy sector, averaging close to $3 per barrel of oil equivalent compared to the industry average that nears $11 per boe. In the second-quarter of 2011, the company saw operating costs reduced to just $1.92 per boe, including transportation.

Operating costs stay so low in part because Peyto’s operations are very geographically concentrated. From January to December 2010, Peyto had 39 producing horizontal wells in Alberta’s Deep Basin, coming in ahead of Bonavista’s 22 wells and Encana’s 16. “A lot of what’s contributed to our low costs is the fact that everything we own we went out and built,” Gee says. “We don’t have a lot of baggage that came along with the acquisition of somebody else’s properties.”

Gee compares his company’s strategy to building a house on your own. When you build a house by hand and know exactly how it works and where everything is, it is much easier to maintain. Peyto fully owns and operates five gas plants to process its production and the company doesn’t carry a large undeveloped land base. Instead, it identifies drilling locations first and then buys the land. By controlling costs in this way, Peyto’s profit margin has climbed to 40 per cent. “We are a growth story and I think growing at about 40 per cent per share over the last year and a half is some of the most spectacular growth in the industry and probably in North America,” Gee says.

Low operating costs are also at the core of Calgary-based Birchcliff Energy Ltd’s success. By controlling, owning and operating essential infrastructure, Birchcliff has managed to produce profits and healthy returns for investors. The returns have been so healthy that after receiving an unsolicited expression of interest, Birchcliff’s board of directors put a “for sale” sign on the company in the fall.

Jeff Tonken helped found the company seven years ago. Today, he’s the president, CEO and a director of Birchcliff, an intermediate oil and gas company. Birchcliff has grown from six employees to 140 and now has an average production of over 17,000 boe per day and a market capitalization of $1.7 billion. “We have low operating costs and we have low infrastructure costs,” Tonken says. “Because we’ve found a significant amount of gas for cheap, we’ve added a lot of reserves for a very low cost and we’ve remained profitable notwithstanding gas prices that are really weak.”

Like Peyto, Tonken’s company builds and operates its own infrastructure, including gas plants and pipelines. “Part of the problem in the natural gas business is that if you discover a bunch of gas but you have to go through third parties for facilities, you have to pay very high processing costs. If gas prices are low, it makes it uneconomical to do it and you start to lose money,” Tonken says. For the second quarter of 2011, Birchcliff’s operating costs were $6.74 per boe.

The company has focused on two resource plays in the Peace River Arch area of Alberta, just north of Grande Prairie. “We chose the area because there was a lot of undeveloped land. Then we went out and bought that undeveloped land and started drilling,” Tonken says.

His firm maintains a substantial undeveloped land base in the area, reflective of its strategy of acquiring undeveloped land close to its production base. In addition to operating horizontal natural gas wells in the Montney/Doig resource play that straddles the Alberta-British Columbia border, Birchcliff also has a rig active on the Worsley light oil resource play, located in the Peace River Arch area. While many start-up companies initially struggle to attract capital, Birchcliff never had that problem. A large shareholder, Seymour Schulich, was involved from the beginning. “He owns 26 per cent of our stock so we’re very well sponsored, meaning we have a big, long-term shareholder who has helped us attract other shareholders,” Tonken says.

That’s not to say, though, that Birchcliff hasn’t had challenges. In addition to dealing with changing commodity prices, the company has experienced the expected growing pains that come with increasing from six to 140 employees in just seven years. “We’ve also come from no production to 18,000 boe per day. That’s growth that all has to be managed,” Tonken says.

He expects that growth to continue, as Birchcliff expands its gas plant to increase processing capacity. “We see a lot of growth, but the key to it is all the growth is in one area where we have high working interests and where we control our infrastructure,” Tonken says. “It’s the same place, same services, drilling the same wells, so it’s just repeatability. We won’t leave our map sheet or lose our focus.”

Both companies have also benefited from being in the right place at the right time. Peyto was formed 13 years ago and built its first gas plant 11 years ago, long before Alberta’s Deep Basin was “in vogue,” as Gee puts it. “Peyto is probably one of the very first resource play companies in that we were focused on the resource plays of the Alberta Deep Basin before anyone else,” Gee says. “We were always focused on this area and saw the advantages of it and we haven’t lost that focus over the last 13 years of operating.”

“We were lucky enough to be one of the leaders on the Montney/Doig natural gas play,” Tonken says. Armed with an early mover advantage, Tonken foresees commodity prices increasing as the current funk squeezes high-cost producers, leading to tighter storage volumes. “What we think will happen over time is that our competitors, if they’re not low-cost producers, they’ll quit drilling natural gas and eventually gas prices will go up over time,” Tonken says.

If that happens, don’t expect Peyto to ramp up production. “It’s only when a commodity goes way up that everybody else has lots of cash so the whole industry rushes out and starts to drill like crazy,” Gee says. “Then service costs go through the roof and everything costs a lot more, and that’s the time when we slow down.”

Type in “Downway” on YouTube and you’ll get a glimpse of Dave Pederson’s former career. Wearing a ball cap and an oversized hoodie, there’s Pederson, the former lead singer and guitarist of the now defunct Calgary punk rock band, sneering and screaming his way through tunes like Dyin’ and Jack That Tastes like Rye with all the gusto of the Sex Pistols’ Johnny Rotten. “I was young and dumb, living in an RV and touring around North America,” Pederson says wistfully. “It was a lot of fun.”

But as Pederson and his bandmates were trying to become rock stars, the Calgary resident was leading something of a double life. During the stretches when Downway wasn’t touring, Pederson would pick up oil and gas jobs to pay the bills. His first petroleum gig was as a welder’s helper and general laborer. Eventually Pederson drifted into the marketing side of the business, working as a sales representative trying to dig up work opportunities for a Grande Prairie-based pipeline company. And it was that job that led Pederson – now 34 years old – to form Tridata Services Ltd.

The company, which was incorporated in 2002, bills itself as an oilfield marketing and sales representation company. What does that mean, exactly? Well, think of Pederson’s company as a fixer of sorts. Tridata Services markets and represents its clients – many of them in the oilfield services sector – to the oil companies and engineering firms that are active in Western Canada’s oil patch.

In essence, Pederson and his team of eight sales representatives help inform clients where the work is, who is doing it and who to contact to be hired for the work. It’s the kind of legwork that can be difficult for an oilfield services business to pull off successfully on its own. But it’s a necessity in growing a business as the sector looks to capitalize on the $44 billion projected to be spent in the petroleum industry in 2011. “A lot of these outfits, such as pipeline facility construction companies, they are based out of small-town Alberta. Coming to Calgary and being connected to Calgary isn’t their number one issue of importance,” Pederson says. “Keeping busy out in the field is what they are concerned about. But keeping busy out in the field has a lot to do with what their connections are like in Calgary.”

Tridata’s expertise is making those connections. Pederson says he and his team have developed a network of contacts within the industry and they know the right people to speak to when oilfield services businesses are looking for work. The company also strives to provide up-to-date information on where that work is occurring. Pederson has had exclusive software designed for Tridata that allows the company to keep track of drilling activity in Western Canada. The software helps his company assemble detailed knowledge about oil and gas projects, which can quickly help identify job opportunities.

And getting to managers and supervisors in charge of contracting promptly – and being knowledgeable about what they are doing – can be invaluable in securing contracts with those companies. “Being first through the door and having a purpose for calling says a lot,” Pederson says. “If you’re the 20th or 30th person that individual has talked to about the work they are doing, their interest has waned in speaking with contractors at that point.”

Although Tridata Services has been around for a decade, it was in 2007 that Pederson decided to take his company to another level. That year Pederson established an office presence for Tridata Services in downtown Calgary after years of working out of his home. Pederson then started adding clients and staff as the business continued to grow.

While toiling on the punk rock scene might not seem like the ideal training ground for an oil and gas entrepreneur, Pederson insists it was. He says playing in a band and dealing with record labels, managers and booking agents in a cutthroat industry has served him well in his post-punk rock career. “When you are in a band, your business is marketing. You are trying to market your band on stage, in an interview, in a video and on your albums. You are a product,” Pederson says. “The game you have to play and the struggles you have to face are ironically similar in the music industry and the oil and gas industry.”

Pederson and Tridata’s approach is working for clients like Arc Line Construction Ltd. A Tridata Services client for six years, owner Joe Bandura says the professionalism and results his Brooks, Alberta-based business has received from Pederson’s company allows him to concentrate on working in the field rather than working Calgary’s boardrooms. “I just phone them and say, ‘Chase this guy.’ We don’t have to do that. It lets us do our jobs,” Bandura says.

While businesses like Arc Line Construction remain Tridata Service’s bread and butter, Pederson recognizes the importance of diversifying his client base. In January the firm took a significant step in that direction by finalizing a partnership with Calgary-based Rainmaker Global Business Development. The relationship is allowing Tridata Services to work with international clients that want to break into Calgary’s energy market.

And while Pederson may have never achieved fame and fortune with Downway, playing in the band did teach him to dream big — something he’s doing with his new company. “When I started playing in the band when I was 18, the goal was to play a show in Calgary,” Pederson says. “We ended up touring all over North America. When I look at Tridata Services, I see a wide open playing field for us and that’s really exciting.”

Boomtowns have a long history of attracting fortune hunters. Saskatchewan’s oil boom is no fabled gold rush, but the rapid development of resource plays bearing names like Viking, Lower Shaunavon and the Bakken does resemble a bonanza in at least one sense. People are as eager to spend money as they are to make it, and thanks to the lucrative revival of old oilfields, diamonds are selling like hotcakes. “Sales have gone up dramatically,” beams Al York, who owns York Jewellers in downtown Weyburn. His father bought the outfit in 1980, but business today is unusually brisk. “We sell more bigger and better quality stones now, in the last three years, than we sold in the last 30 years that we’ve been in business,” York says.

The elevated traffic in precious gems coincides with a renewed sense of confidence in the southeast corner of the province. Local economies are booming and provincial resource coffers are flush. February Crown land sales centered on Weyburn and Estevan topped $18 million. Combined with extensive private freehold agreements, the total makes the Bakken the richest land grab in the province. The total sale of Crown oil and gas rights exceeded $43 million, the second-highest February on record, bringing land sale revenue for the entire 2010-11 fiscal year to $467 million or more than three times the amount collected a year earlier.

The activity has accelerated at such a clip that Energy and Resources Minister Bill Boyd declared following the winter land sales that the industry had officially “roared” back to life. “The outlook is very good,” the minister says, checking his enthusiasm. “We have a very large resource base in place. Companies are looking at the province as a good place to advance with lots of opportunities. The land sales are a good indicator of what we are going to see in the future.”

The indicators are strong in Weyburn. In 2010, the value of residential construction topped $21 million, not quite the value achieved at the onset of the boom ($24 million in 2008), but dramatically higher than the pre-boom value of $5 million just five years ago. With a population swell of almost 1,500 last year, a rise of 14.5 per cent to 11,800, the vacancy rate in Weyburn has been squeezed to less than one per cent. Seventy-seven new residential lots opening this spring are expected to sell quickly. “We’ve been able to stay ahead of the curve, but it’s a challenge,” says Debra Button, the town’s mayor since 2006. “Did we see it coming? There was some coffee shop talk that things could really start to hum down here. But you never know until it happens.”

It’s no secret that Weyburn and surrounding communities in the region sit atop one of the richest untapped oil pools in Western Canada. But it took a “perfect storm” of lucrative oil prices, new horizontal drilling techniques, a stable royalty and regulatory structure – compared to Alberta’s perennial tinkering – plus a handful of resource risk-takers to make the Bakken an attractive place to be.

“It’s been much better than we ever expected,” says Scott Saxberg, chief executive of Crescent Point Energy Corp. With production volumes of 42,000 barrels of oil per day, the Calgary firm is the largest player in the Saskatchewan Bakken. This year marks the company’s 10th anniversary and its fifth year in the Bakken, after buying into the play with a 2006 acquisition of Mission Oil and Gas, itself one of the earliest players in the field.

“When we acquired in the Bakken, it was a half-a-billion-barrel oilfield. Since then, that pool has grown to over five billion barrels of oil in place, to become the second largest light oilfield in Western Canada,” says Saxberg. “It is an exciting place to be.”

With 42,000-barrels-per-day of production, Saxberg’s Crescent Point is the largest player in Saskatchewan’s BakkenPhoto: Todd Korol

The attention is remarkable in part because it’s making up for almost six decades of neglect. The Bakken oilfield was discovered in Montana in 1953 and named for the farmer on whose land the first wells were drilled. However, it was largely ignored as too difficult and too costly to tap. In 1995, a geologist with the United States Geological Survey made a comprehensive field assessment and concluded that the Bakken oil formation contained a staggering 413 billion barrels of crude.

The prospect of a fresh motherlode did not precipitate a drilling frenzy, however. The Bakken resource is “tight oil” trapped in an impermeable layer of 350-million-year-old shale within the Williston Basin, a vast formation under the plains of North Dakota, eastern Montana, southeast Saskatchewan and the western corner of Manitoba. Conventional vertical wells drilled into the shale came up disappointingly dry. Estimates said as little as one per cent of the payload could be tapped with technology of the day.

In 2000, a geologist in Montana took a different route into the Bakken – horizontal. By drilling horizontally into the shale, then fracturing the rock with high-pressure liquid and sand, fissures were created in the source rock through which the oil could flow. The technology was further refined so that fractures could be precisely positioned, creating multiple flow points into one long horizontal well. The advances don’t come cheap. But the added cost of multi-stage frac jobs – in many cases more than double the drilling and well-completion costs of their vertical cousins – is offset by increased productivity.

The technology, which has also unlocked vast amounts of shale gas in the lower 48 states and pockets of Canada, has evolved in a familiar pattern. Much of the activity mirrors the renaissance in shallow gas drilling during the 1990s that produced new industry giants Canadian Natural Resources Ltd. and Husky Energy Inc.

“A lot of money was spent over the years and, yes, there were a lot of failures, but eventually [producers] developed consistent repeatable methods of drilling and increasing the production from shale rock,” says Gary Leach, executive director of the Small Explorers and Producers Association of Canada (SEPAC), whose members include the junior and intermediate-sized companies active in the Canadian side of the Bakken. “It’s made Saskatchewan a very exciting place for investors who fund the companies that are working there.”

The first experimental horizontal wells were drilled in the Saskatchewan Bakken in 2004, based largely on early successes in Montana. “The first three wells were drilled eight miles apart and they all produced light oil,” says Painted Pony Petroleum Ltd. chief executive Patrick Ward, who had a hand in the early production as a vice-president at Innova Exploration. “Within six months to a year, we estimated we had about 48 million barrels of oil in place,” he recalls. “It was a very significant discovery – in hindsight, the largest onshore light oil discovery in Canada for over 50 years.”

According to data from Saskatchewan Energy and Resources, an average of 750 barrels of oil per day was produced in the Bakken in 2004. By 2006, production had climbed to 5,000 barrels per day. From there, the trajectory is steep: 13,500 barrels in 2007; 41,800 in 2008; 54,500 in 2009; and more than 61,000 in the first six months of 2010 from more than 1,000 wells.

In 2007, Painted Pony raced onto the scene. “We started with $12 million and not a single barrel of production,” Ward says. “We’re now over 2,000 barrels per day, so that’s pretty good growth. We’ll probably see another 30 per cent growth this year,” he predicts. “We continue to expand our Bakken potential.”

The technology is expanding, too, as oil companies and their service partners search for better and less expensive means of drilling and fraccing, in the endless pursuit of cutting costs and boosting productivity. “The technology has changed significantly from year to year,” says Crescent Point’s Saxberg, who is introducing innovations such as cement liners and experimenting with water flooding and different concentrations of sand. “We’ve taken initial recovery in the field from 10 per cent to – with water flooding, we think we can get recoveries up over 30 per cent. It’s pretty exciting.”

Based on its Bakken success, Crescent Point has introduced horizontal drilling techniques to its other oil interests: Flat Lake in the North Dakota Bakken, the Lower Shaunavon in southwest Saskatchewan and a tantalizing but unproven area of exploration in southeast Alberta dubbed – optimistically – the Alberta Bakken. Straddling the Montana border south of Lethbridge, it’s drawing a surge of exploratory activity on both sides of the 49th parallel.

Production from the Bakken, expected to crest 1.3 million barrels per day over the next two years, is contributing to a storage glut at Cushing, Oklahoma

The Alberta play is not physically connected to its Saskatchewan cousin, but it is connected in geological time and conditions. Its “tight” shale source rock is Bakken-like, inspiring the same name and optimism that has characterized the original Bakken to the east.

Speculation has followed as companies like Crescent Point, Royal Dutch Shell, Bowood Energy, Murphy Oil and DeeThree Exploration move into the area, quietly snapping up land and establishing exploratory drilling programs that saw a dozen or so wells sunk by the end of 2010.

Crescent Point is leading the pack with five wells drilled or underway. The firm plans to drill 14 new wells in 2011, but it’s too early to assess the resource’s commercial viability. Early activity has coaxed limited oil production, but enough to give Saxberg a sense of qualified optimism. “It’s early days and highly risky,” he cautions. “We’re confident we’ll get oil production out of there but whether it will be economic or not, we’re not certain at this point.”

Alberta’s mature oilfields are also witnessing a revival. Resource plays better known to geologists as Cardium, Pekisko and Pembina are proving valuable after being largely written off as marginal assets whose production lives had run their course. Economic and technological barriers had previously kept recovery rates in legacy oilfields down in the range of 10 to 20 per cent.

“As technology improves, everybody hopes to increase those recovery rates,” says SEPAC’s Leach. “This technology that was first applied on a large scale in Saskatchewan has, in the last 18 to 24 months, been introduced in Alberta with some pretty exciting results in some of our older mature oilfields.”

The renewed activity is good news for an industry that has been in decline for more than a decade. Since the mid-1990s, when Alberta’s conventional production exceeded 300 million barrels per year, extraction has fallen dramatically to 168 million barrels of crude in 2010. At the same time, the younger oilfields of Saskatchewan saw a steady incline in production to 154 million barrels in 2010. It’s a difference of about 40,000 barrels per day.

Could a province better known for potash out-produce its oily neighbor to the west? “It’s not inconceivable,” says Roy Schneider, a spokesperson with Saskatchewan’s Ministry of Energy and Resources, quick to downplay any budding rivalry. “We’re not banking on it and we don’t much care. What’s significant for us is that a huge gap has become an almost insignificant gap.”

Alberta is far from a writeoff. CIBC World Markets projects that a staggering 77 billion barrels of already discovered black gold – much of it in Alberta – lies buried in old oilfields spread throughout the Western Canadian Sedimentary Basin. As oil prices rise, the new technology and horizontal frac jobs become more economic. “That’s where people often lose sight,” observes Ward, with Painted Pony. “People say we’re running out of resources, but as the technology advances and economics change, we can start extracting the stuff that’s harder and is costlier to produce. At a certain price it makes sense.”

While the Alberta government reverses and reviews recent changes to its royalty and regulatory structure, Saskatchewan continues to offer a stable and attractive environment for small and intermediate-sized oil entrepreneurs. “Through that period of difficulty we had in Alberta, Saskatchewan was a real beacon of stability,” Leach says. “It’s easy for the smaller and mid-size oil and gas companies to go to Toronto and New York and Calgary to raise money and persuade investors that Saskatchewan is a great place to invest.”

At York Jewellers in Weyburn, the “diamond rush” shows no sign of abating. Engagement rings are a big seller, York says. But mature clients eager to celebrate anniversaries and special occasions are also buoyant. “Everybody’s just so excited to see opportunity come our way and I really don’t see it stopping.”

Michael Carten knows the challenges of running a renewable energy business in Alberta. When the accidental entrepreneur makes his sales pitch for the future of solar power in a province more accustomed to drill bits and derricks, he frequently gets what he calls the “usual dinosaur reaction.”

But the chief executive of Sustainable Energy Technologies (SET), a Calgary-based company that produces inverters for solar panels, is not deterred. “There’s the potential here to build a company that is Canadian-based and that is actually a competitive player in the renewable energy and alternative energy industry,” he says.

A former senior partner with a leading energy law firm, Carten says he “kind of backed into” the entrepreneur role when he joined a group of investors launching SET in 1999. He has spent the last decade building an international company from a reluctant home market. “In the big picture sense, we’ve actually been creating a company off what amounts to a drawing on a piece of paper when we started,” he says.

Since its early days of dabbling in wind power and fuel cell applications, SET has refined its focus to grid-tied solar power. The company’s main offering is the Sunergy inverter, a device that enables photovoltaic solar panels to be wired in parallel instead of in a series, boosting performance and improving safety. Carten compares the series model to lights on a Christmas tree. If one light goes out, all the lights go out. “If you were to wire those Christmas tree lights in parallel, one of them would go out, but the rest would continue to operate. When it comes to solar panels, it’s the same thing.”

When solar panels are wired in series and one panel operates at half-power, the whole system operates at half-power. By using an inverter, panels can be wired in parallel. The result is that each panel operates independently of the other panels in the system, so even if one panel is operating at half-power, the other panels can continue to operate at their normal output.

The difference plays an important role in harnessing the power of the sun. Shade is a perennial problem for solar-panel setups. An entire system can lose a significant amount of energy when one panel is blocked by dust or sunlight is otherwise obscured. By connecting solar panels in parallel, energy losses no longer affect the entire system. “The parallel solar model is all about saying, ‘Why don’t we look at the whole system operating as an integral unit and see if we can get better economics based on how we put the system together,’” Carten says.

His firm’s stock-in-trade can boost power output by five to 25 per cent. The parallel arrangement also allows solar schemes to operate below 120 volts, which reduces the shock for anyone who might come in contact with a system’s wiring. Parallel solar provides a better “fill factor,” essentially enabling more panels to fit in a given space.

Michael Carten’s Calgary-based firm is increasingly making calls to Ontario to market its productPhotography by Jason Molyneaux

The inverter technology was developed locally at SET’s head office in Calgary. But Carten is unsure his firm will continue to call Alberta home. “The markets aren’t here,” he says.

The solar specialist is focusing increasingly on Ontario’s solar industry, where demand for its devices is driven by the province’s feed-in tariff, which provides a guaranteed pricing structure for renewable electricity production. SET’s inverters were recently selected to power Ontario’s largest solar tracker project. “The market for our product is Ontario; that’s where we’re putting most of our time today, then Europe and then the United States,” Carten says. Sales offices in Toronto and in Athens, Greece, serve SET’s global customers.

The Alberta market is small, Carten says. Although the province is blessed with Canada’s strongest levels of solar irradiation – a key factor in making the alternative power setups worthwhile – the entrepreneur isn’t convinced his technology has a future in Wild Rose Country. Policies that support renewable power schemes are virtually non-existent, while a vast supply of cheap and accessible coal-fired generation makes it tough for solar energy to compete.

Still, he’s committed to the budding sector. “I really believe profoundly that we as Canadians have to create our own technology and create our own products and export them,” he says. “We should play a role in what are going to be the new industries in the next 100 years and this is one of them.”

Regardless of the reception to the inverter technology in Alberta, SET’s future in other markets looks bright. Using numbers pulled from industry forecasts, the company believes the value of its niche market will grow globally from $1.3 billion in 2007 to $5.3 billion in 2012.

The shift from series to parallel solar technology is the most disruptive change happening in the industry right now, Carten believes. Add to that the reduced cost of solar energy – driven chiefly by a combination of favorable subsidies in Ontario and B.C. as well as the improving supply-chain and procurement practices of a maturing sector – and SET’s fortunes are indeed looking bright. “I can see this company as having hundreds of millions of dollars in revenues,” Carten says. “It looks hard to get there from here, but I think the potential is there.”

Recent developments in renewable energy technologies are particularly exciting for Carten. Parallel technology is becoming an industry standard. Few were interested in the novel setup on a recent trip to Europe a year ago, Carten recalls. “Now it’s the buzz in the industry and people are saying, ‘Come on in, I want to talk,’” he says. “And it’s gradually going to get more traction and I think it will become the way in which systems are put together. It’s a classically disruptive technology, and it’s going to change the landscape. It’s going to change who the incumbents are.”

Look for established corporate giants to snap up renewable energy companies this year, PricewaterhouseCoopers says. The budding green sector is poised for a wave of mergers and acquisitions as small project developers of hydro, wind and solar setups look to big firms – from Calgary-based TransAlta Corp. to infrastructure giant General Electric – to realize growth targets.

The current renewable energy landscape in Canada is fragmented, says a PwC report released last fall under the title M&A in the Canadian Renewable Energy Sector. As in other emerging sectors, “The majority of players are undercapitalized junior developers and there is no clear market leader.”

Small companies that have managed to carve out a niche in this emerging sector now face a predicament familiar to some of the “junior” oil firms busy plumbing wells in Western Canada’s oldest oilfields. “They get to a point in time where they’ve really proved up a good body of properties and then they can attract the interest and attention of a bigger company,” says Leanne Sereda, partner in energy tax services with PwC.

Europe led North America in renewable M&A activity through 2010, accounting for 60 per cent of deals compared to 16 per cent in Canada and the U.S. That could change, PwC says. “Many junior developers and their projects are approaching maturation and are ready for construction,” the report notes. Commercializing the ventures “will only become a reality via full or partial divestiture to larger entities with strong balance sheets and the ability to access project financing.” Even traditionally extractive companies like Teck Resources Ltd. have picked up on the trend. The mining giant recently inked a deal with Suncor Energy Inc. to develop a wind farm near Drumheller, Alberta.

But it is junior firms looking for larger project partners that will drive the M&A activity, report author Mike Bowman says. Young players need capital to develop increasingly larger projects, while larger firms and energy utilities are keen to stake out a claim in the budding sector as it becomes more established.

Winnipeg-based Sequoia Energy Inc., fresh from opening a Calgary office, recently purchased Calgary-based C-Free Power Corp. The acquisition fits the pattern described by PwC. Sequoia has spent the last five years amassing a suite of wind and hydro projects. The portfolio will benefit from “being part of a much larger Sequoia team with extensive experience in engineering, community relations and business development,” Sequoia president and chief executive Ron Diduch said in a statement announcing the deal.

Government is also emerging as a key player in driving growth in the renewable sector. Policy-makers “are starting to pay attention and are driving policies and subsidies into the sector to try and encourage development, and those subsidies are making renewable energy projects more economically viable,” says Bowman, vice-president of corporate finance with PwC.

Aggressive regulations in Ontario and British Columbia have already positioned those provinces as renewable energy leaders. Ontario’s feed-in tariff, which offers premium prices for energy generated from renewable schemes, helped drive M&A activity up by 116 per cent since the program launched in 2009. “If investors see that the governments are implementing long-term commitments to the renewable energy sector, then the capital and development will follow,” Bowman says.

Long-term yields available under the green subsidy will start to attract a greater share of institutional capital to the sector, he predicts. The regulatory and price certainty will also yield interest from a growing number of traditional oil, gas and utility players keen to diversify their asset portfolios.

The shift may seem incongruous, but renewable energy allows extractive fossil fuel companies to build capacity in another area of Canada’s increasingly diversified energy mix. Calgary-based TransAlta Corp. is certainly not coasting. The Alberta-based giant has been steadily investing in alternative power since 1997, including a blockbuster purchase of Canadian Hydro Developers Inc. in 2009. Wind and renewable power schemes now comprise more than 20 per cent of the company’s generation portfolio.

Higher prices for fossil fuels will also drive growth in the renewable sphere, Sereda says. “Energy producers want to be energy producers, so they will allocate their capital, for the most part, to their best returns,” she notes. “But many of the big companies will also ensure that they have some level of involvement or some portfolio in the renewable energy sector. They want to be a part of the game, and as these things are evolving they want to make sure they understand the industry.”

Hedging against the unknowns of legislation aimed at reducing emissions of carbon dioxide blamed for global warming is also part of a growing sense of corporate social responsibility on display in Canadian boardrooms. Companies ranging from food distributor Loblaws to furniture giant Ikea Canada are participating in marginal ways. By far the largest player to directly invest in projects is Google Inc., through its green business operations division. The search-engine giant has partnered with several companies, including the Marubeni Corporation, on an offshore wind project that promises to connect 6,000 megawatts of power to the American electricity grid.

Canadians are well-positioned to partner with firms in emerging markets like Brazil, China and India, PwC says. Brookfield Renewable Power Inc. has made inroads in Brazil, where it owns and operates 34 hydro facilities.

In Alberta, renewable power is a tougher sell. The energy province uses coal to generate roughly two-thirds of its electricity. Widespread adoption of renewable systems to replace the base-load capacity generated by the dirtiest of fossil fuels won’t happen without reaching into the deep pockets of established energy titans, PwC suggests. That’s because, among other challenges, a greener future hinges on “increased access to capital.”

Brett Davidson, CEO and president of Wavefront Technology Solutions Inc.
Photography by 3ten

When the largest earthquake ever recorded in North America struck Alaska in 1964, production from oil wells in Alberta increased. Recreating that effect, first in the laboratory and later in the field, has consumed an Edmonton-based company for the past 28 years. “I can tell you developing a new technology for the oil industry is not for the faint of heart,” says Brett Davidson, the CEO and president of Wavefront Technology Solutions Inc.

Although Wavefront’s trademarked Powerwave System has a proven record of improving production rates by injecting liquids or super-critical gases into reservoirs, attracting companies to adopt the system has proved challenging. “The potential upside [of Powerwave] is huge, but there’s always some skittishness the first time,” says Davidson, noting that no one wants to be the first to adopt a new technology.

Though Wavefront has had clients since 2007, now, for the first time, the firm has made public one of the Canadian users of its Powerwave systems. Naming client TriAxon Oil Corp., a Calgary-based private energy firm that deployed six Powerwave systems in November 2010, is a potential endorsement that may help to propel Wavefront beyond a specialized science firm. The deal will enable disclosure of results to corroborate the inventor’s claims for the technology.

Davidson says the Powerwave system improves oil production rates and extends field life through a system that reaches previously inaccessible oil by working similar to a kink in a garden hose. “Powerwave is a game-changing technology,” Davidson believes.

Just as the advent of hydraulic fracturing technology taps into Alberta’s oldest oilfields, Wavefront also targets previously hard-to-reach reserves of “tight” oil through new technology – in this case an injection system. Conventional approaches to oil recovery using a fluid-flooding process work like a normal garden hose, says Davidson. Constant pressure flows from the injection location to the production location and follows the path of least resistance, meaning the fluid often penetrates poorly and does not reach all the oil.

Wavefront developed the Powerwave system from research built on understanding the effect of earthquakes on oil production. Earlier versions of the device were used on the surface, but now the technology operates down in the well. It works by rapidly opening and closing a valve, similar to the release of a kink in a garden hose or the beating of an animal heart. That release adds momentum to the liquid being injected and distributes the fluids more uniformly. Oil trapped in nooks and crannies is accessed by the pulsing liquid and moves towards production wells, ultimately increasing oil production.

For Jeff Saponja, president and chief executive of TriAxon Oil Corp., using technologies like Powerwave is what his “junior” energy firm is all about. “We’re not taking the risk as much on the exploration play anymore – we’re taking the risk on implementing newer technologies,” says Saponja, who believes so strongly in the technology that he joined Wavefront’s board of directors last July. “We prove this technology works in certain fields and that’s where we build value for our shareholders. That is the evolution of the junior model.”

Saponja says it’s been known for a long time that large amounts of oil remain in the ground. “Getting that oil out is all about new ideas, creative ideas, the adoption of new technologies and developing new technologies – that’s where the future of this province is,” Saponja says. “There isn’t going to be a lot of discoveries anymore. It’s going to be discoveries in innovations and new ideas that’s going to make the difference.”

Saponja identified Wavefront’s technology while looking for a product that would inject more water into sandstone reservoirs. He started using Powerwave in December 2009 in the Pembina Cardium field with TriAxon Resources Ltd., TriAxon’s predecessor. The company was acquired by Crescent Point Energy Corp. before Saponja had the chance to observe the performance of the tool.

TriAxon’s second incarnation, born last spring, recently installed six Powerwave systems in a Viking oil play in the Harmattan area. “With anything with water injection, you’re not going to see a response right away,” Saponja says. TriAxon is the first visible face of Wavefront’s clients, yet users have been quietly adopting Powerwave systems since September 2007. That’s when the company’s first commercial pilot project began in eastern Alberta.

The firm’s first client started out with three tools in September 2007 and is now using 63 of the devices. Wavefront’s clients may be reluctant to be identified, due to competitive advantage reasons, but Davidson believes his company is on to something.

Recent developments suggest the same. In October 2009 Wavefront signed a letter of intent with Pemex in Mexico. License and rental agreements are under discussion with Petroleum Development Oman and several operating companies around the globe. More than 100 Powerwave tools are currently in operation throughout North America, mostly concentrated in Alberta, Texas and California.

Davidson says Powerwave’s multiple tool designs work in various reservoir conditions. No two reservoirs are alike, but operators can expect production increases of 25 to 200 per cent for the wells influenced by the Powerwave-driven injection well – typically one Powerwave system is surrounded by four to six production wells – and an increase in ultimate recovery of two to five per cent.

While early adopters have been slow to step forward and identify themselves, Davidson is confident that Powerwave has a role to play in tapping depleted reservoirs. He says Wavefront stands to capitalize on new markets as companies turn to the Powerwave device to increase overall recovery without drilling new wells.

The company has an ambitious 10-year goal to capture 10 per cent of the market for breathing new life into old oilfields, which would mean a rollout of some 25,000 Powerwave tools. “We’re at that tipping point,” says Davidson. “We have enough clients and enough field evidence to demonstrate that this technology should be well used. We don’t see growing by five or 10 tools a year. We see doubling tools this year and doubling tools thereafter, because the results are just too compelling.”

Model Idea: David Stenning, President Of Sea Ng Corp.
Photography by Jason Molyneaux

More than a decade of striving to carry out an idea – an invention that is patented, backed by three corporate giants, and yet still not in action – has made David Stenning a stone realist. “It’s very hard – harder than I ever imagined,” he says.

In the international energy transportation arena where he works as president of Calgary-based Sea NG Corp. he says, “It’s a lot harder to put together commercial deals than I ever imagined. There are many companies involved. There are countries. There are a lot of people you have to get lined up.”

His experience with Sea NG’s elegantly simple brainchild – a natural gas counterpart to marine container shipping – has convinced him that technology’s heroic age is over. He sees no room left for adventurers to try out rickety prototypes of great advances in a modern era of obsessions with profits, safety, and environmental and socioeconomic precautions. “The Wright brothers would never be successful today,” Stenning says.

But he is not disillusioned. His firm’s innovation is no improvised rattletrap of bicycle tubes, baling wire, cloth and a shaky motor. Sea NG’s design for a world first – an ocean-going compressed natural gas (CNG) freighter – is approved by the American Bureau of Shipping. A 10-hectare (25-acre) ship construction site is reserved in South Korea’s Gunsan Free Trade Zone.

The key design element – steel carousels, trademarked Coselles, that each hold four million cubic feet of methane compressed at 4,000 pounds per square inch into 2,100 meters of coiled pipe 15 centimeters in diameter – has been vetted by Det Norske Veritas, the Norwegian counterpart to the Lloyd’s of London insurance exchange and watchdog.

Stenning cut his professional teeth with a model of successful engineering innovation. He worked for the late Dome Petroleum Ltd.’s 1970s and ’80s Beaufort Sea oil exploration armada, Canadian Marine Drilling. Financial recklessness sank Dome, not technological folly. “I’m not new to trying to do something,” Stenning says. “Why would I still do this if a lot of people didn’t think it was a good idea? I’m not a mad scientist.”

Sea NG’s chief executive officer, serial oil company builder Barrie Wright, adds, “This feels like it’s really doable.” He gives the firm a good chance of landing its first commercial development in 2011.

Stenning and Wright are in good company. As of September, Enbridge Inc. added its weight as Canada’s top oil pipeline and gas distribution enterprise to a project alliance led by Sea NG. The other members are Japanese conglomerate Marubeni Corp. and Teekay Corp., owner of a global tanker fleet that carries about 10 per cent of the world’s ocean-going oil supplies aboard a fleet of more than 150 vessels.

The group has scored a tantalizing near-hit. In mid-2009 an Egyptian and Greek energy transportation partnership, Medcarrier SAE, selected Sea NG to deliver Middle East gas across the Mediterranean Sea to a power station in Crete. The deal was foiled by a financial crisis that has left Greece teetering on the brink of national bankruptcy.

Optimism that the dormant Greek deal will be replaced is rooted in the emerging shale gas revolution. The new production method is expected to eventually make the cleanest fossil fuel plentiful and stabilize its previously violently fluctuating prices into a reasonable, predictable range everywhere. “There’s a huge driver for people to change from oil to natural gas,” Stenning says. He points to a continuing, wide divergence between prices for the two fuels.

If they traded as equals with their value set according to their comparative energy content, the standard gas sales unit of 1,000 cubic feet would cost one-sixth as much as a barrel of oil. Instead, gas consistently fetched only one-eighteenth or less of the oil price across North America for the last two years as shale output grew while consumption stayed flat. In effect, the market value of gas as energy is about 66 to 70 per cent less than oil.

The Paris-based International Energy Agency (IEA) predicts the discount will spread to the rest of the world as shale production expands. Growing supplies are expected to cause irresistible economic pressure to break European and Asian commercial traditions of indexing gas to oil prices with an energy content formula.

The specialty of Calgary’s aspiring shipping magnates is catching international eyes. In its latest annual World Energy Outlook, a bible among experts and forecasters, the IEA identifies marine CNG delivery as an attractive alternative for gas from the Caspian Sea and Black Sea regions.

As in Canada and the United States, international pipeline projects run into business, political and environmental obstacles. The traditional ocean transportation method, liquefied natural gas (LNG) tankers, is uneconomic over the short distances to markets from Caspian and Black wells, the agency says.

The old technique requires multibillion-dollar plants to chill production into a stable liquid at -168°C, massive tankers to transport it, and big “regasification” operations to warm the gas back up into usable form. The IEA calculates that marine CNG delivery would be more expensive than pipelines but potentially less than half the cost of an LNG system.

Sea NG is not revealing a replacement for the foiled Greek plan until a new deal is done. The Caribbean Sea is the firm’s early favorite target. Gas production is strong in Trinidad and Tobago. There are potential customers that are too small to support LNG terminals but big enough to justify CNG deliveries such as oil-fired power stations in Barbados, Panama and Martinique. “We’re trying to break a new idea into two conservative industries [energy and shipping],” says Stenning. “We’re getting close. The key is to get one contract, and get it up and running.”

Stenning, 58, vows to be on his first CNG vessel’s maiden voyage well before he hits retirement age. “This is my cabin – right there,” he says, pointing to a deckhouse porthole on an artist rendering of a Coselle freighter displayed in his downtown Calgary office. “That ship won’t sail without me.”

Between plains to the east and the Rockies to the west rises Pink Mountain, a British Columbia peak named after its glow at sunrise. A pretty problem that could only be solved with advanced technology brought an Alberta company to the location at mile 143 on the Alaska Highway.

A rich natural gas discovery was made on the mountain top at an elevation of 5,200 feet (1,560 meters). Completing the exploration well for production was the easy part. Installing a pipeline to move the gas from the well to the foot of the mountain proved to be much more difficult. Enter Canadian Horizontal Drilling Ltd.

The firm, founded in 1991 by Kelly Bradford, is a pioneer of a construction technique that provides an alternative to conventional open trenches. Boring holes to cross obstacles where ditches are environmentally inappropriate or physically impossible is his Wetaskiwin-based contracting outfit’s forte.

By drilling uphill for 1,390 feet (417 meters), vertically through hard quartz arenite, Canadian Horizontal connected the mountain well to the gas delivery grid in 2004. The project set a record for the greatest elevation change completed by horizontal directional drilling.

“There’s always a sense of accomplishment when you successfully complete a drill and pull the product pipe through,” says Cory Reed, the firm’s 41-year-old general manager. Reed, who calls himself a “relocated Saskatchewanite,” says he moved to Alberta as a land of opportunity for the “entrepreneurial type of spirit.” His 18 months on the job to date have been studded with assignments on the frontier of industrial technology.

While horizontal directional drilling is coming into widespread use for installing pipelines below watercourses and other infrastructure, the method was in its infancy when Bradford started the company. He saw early forms of horizontal directional drilling in the United States and recognized Canadian market opportunities. “He basically bought and built some rigs and continued to grow the company after that,” says Reed.

The firm designed and built the first horizontal directional drilling rig in Canada, and has stayed on the technology’s leading edge. The specialty is expected to be in high demand for projects such as the proposed Northern Gateway Pipeline.

Enbridge Inc.’s $5.5-billion plan for a 1,172-kilometer oil sands export route from Edmonton to a new marine terminal on B.C.’s Pacific Coast includes 773 river crossings: 690 are deemed routine but 83 require special care and are under study.

If the project obtains regulatory approval and construction goes ahead, horizontal directional drilling has been identified as a preferred crossing method for some of those sensitive or difficult spots, including the Athabasca River in Alberta.

Contractors and regulators alike embrace the technology enthusiastically as an environmental advance. A pipeline construction manual developed by the Canadian Association of Petroleum Producers (CAPP) says horizontal directional drilling leaves an “invisible footprint,” with no tree-cutting or disruption of watercourses except where the pipe enters and exits sensitive or difficult areas.

“It’s a very unique field with interesting projects and a specialty type of work,” says Reed, a civil engineer who has 20 years of oilfield construction experience. “I just enjoy the interface with different clients and the broad range of oil and gas and municipal clients.”

As Reed outlines conditions dealt with by Canadian Horizontal, from the logistics of operating in remote areas to the northern seasonal pattern of working in winter when the frozen ground supports heavy equipment, a visitor senses that the method’s sometimes spectacular results are no easy feat. The Pink Mountain project was a classic case.

In a paper written for the North American Society for Trenchless Technology (NASTT), Canadian Horizontal engineer James Murphy describes a long list of tall orders that had to be filled to do the B.C. job. The firm had to contend with a daunting vertical drilled height, hard rock in the top half of the mountain and doing all the work during winter. The gas well’s owner recognized the difficulties by using a form of contract that shared the risks.

The route was selected to minimize environmental effects. More than 90 per cent of the pipeline route used existing seismic cut lines. Canadian Horizontal used a 500,000-pound (225,000-kilogram) but portable rig that it designed and built for difficult assignments.

Initial stages of the drilling turned out to be much harder than anticipated. The equipment and crew ran into unexpected free flowing water, rising waiting times for fluid to drain from the drill stem as the bit progressed up through the mountain, and breaks in wires used by the remote steering system. The drilling fluid also became highly abrasive due to fine cuttings from the quartz arenite.

“These are challenging projects,” says Reed. “You’re always dealing with different geotechnical formations and different drilling conditions and things are always so variable. You always have to be willing to make changes. You have to have a good crew, obviously, and experienced people.”

At Pink Mountain, the operation made changes on the spot such as switching to a wireless steering tool and placing float valves in the drill string. Steering was the biggest single problem. Special machinery for overcoming friction and resistance was shipped to the site.

Constant work on refinements of the method has the firm on the top of its game. “It is always important to advance the technique by learning from each and every project,” says Murphy’s paper. “This mountain drill was an excellent learning experience for both the owner and the contractor.”

Canadian Horizontal is up to 6,000 successful drills and still counting. The company has completed crossings of rivers, using pairs of rigs stationed on both banks, across most of northern B.C. and Alberta. Along with Pink Mountain, notable projects include installing the largest plastic pipe ever attempted by horizontal directional drilling: a sewer line 36 inches (90 centimeters) in diameter beneath the Red Deer River. A project that bored through 1,660 meters beneath the Peace River at Taylor, B.C., set a record for its time as the longest crossing completed in Canada.

Not all the work is generated by the oil and gas industry. For municipal clients, Canadian Horizontal offers a full-service package of consulting, engineering, design, construction and site restoration, while also financing the project. Upon successful completion, the client buys the crossing at an agreed price.

Money isn’t everything in this business combination of high technology and rugged working conditions. “Probably my favorite part of the job,” says Reed, “is being out on the job site and seeing a successful project or successful pipe being pulled in.”

A pungent whiff can still be had of the natural leak from a geological treasure chest that inspired the well which started Alberta on its path to become an international-scale energy supplier 96 years ago. During spring thaws, escaping methane soaked in gasoline-like “condensate” vapor makes frigid pools of water and slush left by melting snow foam, bubble and hiss.

No monument marks the seep that lured rancher William Herron into founding the western Canadian clan of oil go-getters by setting a famous example of hustling to raise money, recruit backers, buy mineral rights, and drill a gusher. The smelly cradle of industry and wealth beside the Sheep River lies off the beaten path behind a security fence around the mothballed Turner Valley gas processing plant about 60 kilometers south of downtown Calgary.

But the veil of obscurity may be lifted in time for the 2014 centennial of Alberta’s first commercially significant oilfield. After two decades as a ward of cultural and environmental protection specialists under provincial and national historic site designations, the old plant is poised for reconstruction as a landmark interpretive center.

The development plan by architect Lorne Simpson – in combination with the nearby towns of Turner Valley and Black Diamond, in picturesque settings and ranching regions in the foothills of the Rocky Mountains – has potential to put fresh life into Alberta’s image. The scheme would do double duty of putting a human face on the industry and tracing the evolution of provincial resource stewardship.

And industrialists, looking for counters to critics’ one-sided publicity portraits of Alberta oil as all evil, might at last throw their weight behind the interpretive center project. A half-day site tour and briefing this summer lured out representatives of the Canadian Association of Petroleum Producers, Small Explorers and Producers Association of Canada, Association of Professional Engineers, Geologists and Geophysicists of Alberta, Canadian Society of Petroleum Geologists, Gas Processing Association of Canada, Canadian Society of Petroleum Geologists, Canadian Petroleum History Society, Canadian Society of Exploration Geophysicists, Canadian Association of Geophysical Contractors and Calgary Chamber of Commerce. The pitch for support is also being heard by the Canadian Energy Pipeline Association, Canadian Association of Oilwell Drilling Contractors, Petroleum Services Association of Canada, Alberta Enterprise Group and Canadian Manufacturers and Exporters Association.

Out on the tour, Ian Clarke says, “The whole thing here is about the life of southern Alberta.” He has worked for 30 years on the preservation plan as regional director in Alberta Culture and Community Spirit’s historic sites and museums branch. “Our commemoration is about the beginnings of the industry here and what it meant for Alberta.”

Among its features, the place highlights entrepreneurial roots. Unlike big oil sectors in the Middle East, North Sea, Africa and South America, Alberta production is a case of homegrown enterprise coming first and turning in a strong performance that attracted global corporations.

Herron started the show by floating Calgary Petroleum Products Co. as an ambitious rancher from nearby Okotoks who saw a bigger future for the Turner Valley seep than its pioneer-era use as campfire fuel for cattle drives. He had a talent for selling his vision. He drummed up investment from local luminaries such as Sen. James Lougheed, R.B. Bennett and A.E. Cross. The visionary was also a realist. He understood that he lacked crucial technical skills. The top of the Turner Valley fossil-fuel vault was 800 meters underground. It was found because Herron recruited drilling expert Archibald Dingman, a veteran of the American industry’s 19th-century Pennsylvania cradle that the discovery well was eventually named after.

The Turner Valley plantbegan as hazardous equipment for separating hydrocarbon liquids from the initial discovery’s dominant natural gas. At the time there was only one other operation like it, in West Virginia. Local ownership lasted for six years until the plant burned down in 1920. Herron’s group could not afford to start over. Far larger Imperial Oil Ltd., majority-owned by an ancestor of ExxonMobil Corp., bought the plant for subsidiary Royalite Oil Co.

As a wealth and job factory, Turner Valley helped inspire an epic resource-rights political campaign that culminated in the historic transfer of constitutional title to Alberta’s mineral riches over to the provincial government from Ottawa in 1930. Coupled with recurring oil rushes, the switch set off a decade of legal and political battles that laid cornerstones of modern drilling, production, safety and environmental regulation by the province’s Energy Resources Conservation Board. The Alberta model in turn spread across Canada when the federal government created the National Energy Board in 1959 with ERCB veteran Ian McKinnon as its founding chairman.

The Turner Valley site traces parallel industry and government evolution. The onset, effects and costs of environmental regulation show, for instance, in structures for cleaning up “sour” gas steeped in lethal hydrogen sulphide. The plant originally vented hazardous waste into the atmosphere with tall exhaust stacks. But resulting rotten-egg odors, health risks and environmental threats lost their early acceptance as nasty but inevitable side-effects of economic success. A long history of ever-tighter ERCB controls began in 1952.

Since the plant shut down in 1985 and the site was turned over to the government, it has been plagued by vandalism, floods, and internal hazards such as asbestos insulation, soil contamination, and mercury leaks from old equipment. So far, about $16 million in public money has been spent on preserving and cleaning up the place to a point where it is safe to visit.

A 2003 flood put a stop to public tours. But access and guides are provided to industry groups. Clarke predicts that the historical site can be completed and reopened for another $8 million. Industry is being given open invitations to start Turner Valley partnerships ranging from construction support to education programs for school children. “It’s important for us to remember where this all came from,” says Clarke. “It’s important to remember the people that were at the plant and the society that grew up around it – the society of ranchers, farmers and oilmen that made this part of Alberta.”

When industry affects nature and communities, Piers Fothergill would rather make a difference than complain. As president of Tera Environmental Consultants he bridges the gap between livelihoods and conservation. While slower and harder, his firm’s role has rewards that top the kicks and fame of venting and protesting. “It’s feel-good work,” Fothergill says.

He is a professional green who rejects the environmentalist label. “I call myself an environmental manager.” He describes this occupation as, “You help protect something at the same time as you help somebody get a project approved. You’ve guided people to do things. You’ve had a more significant impact than standing in the bleachers and waving a placard. We all feel good coming to work here.”

It would be hard to find someone with better green credentials. The environment is no sideline for Fothergill.

Born in Britain and raised in Ottawa and Calgary, he earned his first university degree in a rare 1970s blend of biology and geography. He called his focus on relationships among plants, animals and the landscape “biogeography.” By the time he was ready to take his second degree in the 1980s, official scholarship caught up. A formal academic structure evolved from novel study plans like his, enabling him to earn a recognized professional ticket as a master of environmental design.

Tera highlights a long-range trend of increasing practical uses for green knowledge. The gratifying niche of adapting industry and its natural and human surroundings to one another is a business growth field.

The firm’s stock-in-trade, environmental impact assessments known as EIAs for short, has a long pedigree in Alberta. The first one was a 35-page document prepared in six weeks by a couple of experts for $10,000 on a fertilizer manufacturing project southeast of Calgary at Carseland. The service has grown into multi-volume reports that can employ scores of specialists for years and cost millions of dollars.

While public expectations and government environmental standards rose steadily, adverse economic conditions made the field a slow starter in the 1980s. Fothergill, age 51, recalls, “It wasn’t much of a career path in those days. It was a tough time to graduate.”

Green business potential languished like every other facet of Alberta industry thanks to the hotly contested 1980 National Energy Program, followed by the nasty twist of economic fate that dealt out oil and gas market collapses soon after the ’85 Western Accord on Energy between Ottawa and the provinces scrapped federal price regulation. “There was not much of an industry and not much work. During the ’80s not a lot of people were doing this,” says Fothergill.

Alberta environmental business pioneers were often specialists who formed tiny consulting firms after they were cut adrift during the lean years by waves of staff paring, mergers, restructuring and work out-sourcing among troubled oil and gas companies. The field took off in the 1990s as reviving energy markets sprouted projects that needed experts to make them tolerable to the spreading green popular conscience and its expression in increasingly voluminous regulation.

Tera Environmental – originally a brainchild of prominent Calgary engineer, naturalist and ex-oil company employee Howard Heffler – has grown up from a one-man shop into a consulting powerhouse with a staff of 150 over its 27-year history. Based in Calgary with personnel across Canada from British Columbia to Newfoundland and Labrador, the firm
has completed more than 6,000 projects.

As a private company, Tera does not disclose financial results. Nor do the owners have any plans to cash in on current fashion for green investment by putting the firm onto the stock exchange and selling an initial public offering of shares. The team prizes its independence, Fothergill says. “It’s a slow and steady growth model.”

Customers can be as small as novice oil companies that require environmental due diligence done on a well or two, in case the drilling turns out to be in a sensitive area. But Tera’s forte is the opposite end of the industry spectrum: pipeline projects.

Among the big Tera jobs have been the EIAs for the extension of natural gas service into Banff National Park, the Alliance gas export route from northeastern British Columbia to Chicago, the high-profile 2007-08 construction of oil shipping capacity additions to Kinder Morgan Canada Inc.’s Trans Mountain Pipe Line across Jasper National Park and B.C.’s Mount Robson Provincial Park, and the proposed 1,200-kilometer Mackenzie Valley Pipeline. Current assignments include the environmental work on about 1,680 kilometers of Canadian legs in the mammoth American Arctic gas line planned to cross Alaska, the Yukon, B.C. and Alberta.

As a veteran of assessing linear developments for the oil and gas industry, Fothergill figures Tera has transferable skills that make it a strong candidate to do EIAs for the emerging new generation of power transmission lines and road and railway projects. The skills include managing work on tight schedules by teams of 100 or more specialists in 10 or more technical disciplines from archeology to zoology.

Professional green knowledge goes well beyond identifying friction between industry, nature and communities. Project owners are guided into solutions. Probes into issues from aboriginal traditional rights to species-at-risk assessments are not afterthoughts. “We are brought in very early on in project planning,” Fothergill says.

Tera’s work often begins with confidential meetings in corporate board rooms, long before development plans are made final and announced. Routes are modified before fights break out. Compensation is devised, such as improving alternative wildlife areas near projects if intruding on sensitive terrain in their path is unavoidable.

“You can use all sorts of imagination. The sky’s the limit,” Fothergill says. But to make it into action ideas have to stand up to scrutiny. Environmental professionals are held accountable. Regulatory agencies make EIA participants testify under oath about their conclusions. “You’ve got to do your job. You’ll be grilled. Your authority and qualifications will be questioned,” says Tera’s president, a veteran of many witness stands. As a professional green, “You can’t fake it.”

Learn to spell Pimee, the Cree word for oil. Aboriginal production will grow – a lot, vows Joe Dion, a hereditary Kehewin chief from the southern arm of the bitumen belt that starts northeast of Edmonton and runs along the border between Alberta and Saskatchewan.

Dion grins when he says, “We’re getting pretty restless.” His allusion to the old saying about natives is a good-humored way of saying he means business as president of Frog Lake Energy Resources Corp. (FLERC). “We’ve got a bit of money,” he adds as he describes plans for the firm to grow up into an industry force.

In less than 10 years, production by the community-owned oil venture of Frog Lake First Nation has multiplied 54-fold to a current 1,300 barrels daily from a scratch start of 24 barrels. “We hope to double production this year,” says Dion. A long-range, ambitious growth program begins with 90 wells that will be drilled in 2010 on the 225-square-kilometer Frog Lake community land reserve by development joint ventures with Twin Butte Energy Ltd. and Canadian Natural Resources Ltd.

While maintaining its old connections, FLERC is also stepping forward as the first aboriginal oil and gas enterprise that has obtained a driver’s license-like permit to operate drilling and production. “We’re the first fully operational, wholly First Nation-owned oil company in Canada,” says Dion.

The competence certificate enables the firm to grow beyond the traditional pattern of native forays into energy as silent, subordinate partners cast in supporting roles for mainstream industrial corporations. While pursuing a large portfolio of still-untapped drilling targets on the community’s own reserve, Dion is on the prowl for outside opportunities.

Initially the growth scheme is expected to focus on the Frog Lake Cree’s larger traditional hunting and trapping territory spanning the oil-rich region between Cold Lake and Lloydminster. The operating license gives FLERC the same wide array of options that the strongest oil juniors have for growth: drilling, conversion into a publicly traded corporation able to raise funds with share sales on stock exchanges, or lining up supporting partners. “The world is your oyster,” Dion says. He adds that he can conceive of eventually reaching out for development opportunities beyond North America. As in Western and Northern Canada, other countries have resource-rich areas where an aboriginal identity and cultural know-how are potential advantages.